SECURITIES AND EXCHANGE COMMISSION
_________________
FORM 10-K
(Mark One)
OR
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act: None.
Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or in any amendment to this Form 10-K. o
Indicate by check mark whether each registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).
State the aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of each registrant’s most recently completed second fiscal quarter:
The number of shares outstanding of each registrant’s common stock as of March 14, 2005
DOCUMENTS INCORPORATED BY REFERENCE
Arizona Public Service Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.
This combined Form 10-K is separately filed by Pinnacle West Capital Corporation and Arizona Public Service Company. Each registrant is filing on its own behalf all of the information contained in this Form 10-K that relates to such registrant. Neither registrant is filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.
TABLE OF CONTENTS
i
GLOSSARY
ACC – Arizona Corporation Commission
ADEQ – Arizona Department of Environmental Quality
AFUDC – allowance for funds used during construction
AISA – Arizona Independent Scheduling Administrator
ALJ – Administrative Law Judge
ANPP – Arizona Nuclear Power Project, also known as Palo Verde
APS – Arizona Public Service Company, a subsidiary of the Company
APS Energy Services – APS Energy Services Company, Inc., a subsidiary of the Company
CC&N – Certificate of Convenience and Necessity
Cholla – Cholla Power Plant
Citizens – Citizens Communications Company
Clean Air Act – Clean Air Act, as amended
Company – Pinnacle West Capital Corporation
CPUC – California Public Utility Commission
DOE – United States Department of Energy
EITF – FASB’s Emerging Issues Task Force
El Dorado – El Dorado Investment Company, a subsidiary of the Company
EPA – United States Environmental Protection Agency
ERMC – Energy Risk Management Committee
FASB – Financial Accounting Standards Board
FERC – United States Federal Energy Regulatory Commission
FIN – FASB Interpretation
Financing Order – ACC Order that authorized APS’ $500 million loan to Pinnacle West Energy in May 2003
FIP – Federal Implementation Plan
Four Corners – Four Corners Power Plant
FSP – FASB Staff Position
GAAP – accounting principles generally accepted in the United States of America
IRS – United States Internal Revenue Service
ISO – California Independent System Operator
kW – kilowatt, one thousand watts
kWh – kilowatt-hour, one thousand watts per hour
Moody’s – Moody’s Investors Service
MW – megawatt, one million watts
MWh – megawatt-hours, one million watts per hour
NAC – collectively, NAC Holding Inc. and NAC International Inc., subsidiaries of El Dorado that were sold in November 2004
Native Load – retail and wholesale sales supplied under traditional cost-based rate regulation
1999 Settlement Agreement – comprehensive settlement agreement related to the implementation of retail electric competition
NRC – United States Nuclear Regulatory Commission
Nuclear Waste Act – Nuclear Waste Policy Act of 1982, as amended
OCI – other comprehensive income
Palo Verde – Palo Verde Nuclear Generating Station, also known as ANPP
PG&E – PG&E Corporation
Pinnacle West – Pinnacle West Capital Corporation, the Company
Pinnacle West Energy – Pinnacle West Energy Corporation, a subsidiary of the Company
PPL Sundance – PPL Sundance Energy, LLC
PRP – potentially responsible parties under the Superfund Act
PSA – power supply adjuster
PWEC Dedicated Assets – the following Pinnacle West Energy power plants, each of which is dedicated to serving APS’ customers: Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3
PX – California Power Exchange
RFP – request for proposals
RTO – regional transmission organization
Rules – ACC retail electric competition rules
Salt River Project – Salt River Project Agricultural Improvement and Power District
SCE – Southern California Edison Company
SEC – United States Securities and Exchange Commission
SFAS – Statement of Financial Accounting Standards
SIP – State Implementation Plan
SNWA – Southern Nevada Water Authority
Spark Spread – Excess of market power price over market gas price at a specific location
2
SPE – special-purpose entity
Standard & Poor’s – Standard & Poor’s Corporation
SunCor – SunCor Development Company, a subsidiary of the Company
Sundance Plant – PPL Sundance’s 450-megawatt generating facility located approximately 55 miles southeast of Phoenix, Arizona
Superfund – Comprehensive Environmental Response, Compensation and Liability Act
T&D – transmission and distribution
Track A Order – ACC order dated September 10, 2002 regarding generation asset transfers and related issues
Track B Order – ACC order dated March 14, 2003 regarding competitive solicitation requirements for power purchases by Arizona’s investor-owned electric utilities
Trading – energy-related activities entered into with the objective of generating profits on changes in market prices
2004 Settlement Agreement – an agreement proposing terms under which APS’ general rate case would be settled
VIE – variable interest entity
WestConnect – WestConnect RTO, LLC, a proposed RTO to be formed by owners of electric transmission lines in the southwestern United States
3
INTRODUCTION
Filing Format
This Annual Report on Form 10-K is a combined report being filed by two separate registrants: Pinnacle West and APS. The information required with respect to each company is set forth within the applicable items.
The Management’s Discussion and Analysis of Financial Condition and Results of Operations included under Item 7 of this report is divided into the following two sections:
Item 8 of this report includes Consolidated Financial Statements of Pinnacle West and Financial Statements of APS. Item 8 also includes Notes to Pinnacle West’s Consolidated Financial Statements, the majority of which also relate to APS, and Supplemental Notes to APS’ Financial Statements.
PART I
ITEM 1. BUSINESS
OVERVIEW
General
Pinnacle West was incorporated in 1985 under the laws of the State of Arizona and owns all of the outstanding equity securities of APS, its major subsidiary. APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. Through its marketing and trading division, APS also generates, sells and delivers electricity to wholesale customers in the western United States.
Pinnacle West’s other significant subsidiaries are Pinnacle West Energy, which owns and operates unregulated generating plants; APS Energy Services, which provides competitive energy services and products in the western United States; and SunCor, which is engaged in real estate development activities. Each of these subsidiaries is discussed in greater detail below. See “Business of Pinnacle West Energy Corporation,” “Business of APS Energy Services Company, Inc.” and “Business of SunCor Development Company” in this Item 1.
4
Business Segments
Pinnacle West has three principal business segments (determined by products, services and the regulatory environment):
See Note 17 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for financial information about the business segments.
APS General Rate Case
APS’ general rate case pending before the ACC is the key issue affecting Pinnacle West’s and APS’ outlook. As discussed in greater detail in Note 3 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8, on August 18, 2004, a substantial majority of the parties to the rate case, including APS, the ACC staff, the Arizona Residential Utility Consumer Office, other customer and advocacy groups, and merchant power plant intervenors entered into the 2004 Settlement Agreement, which proposes terms under which the rate case would be settled.
On February 28, 2005, the administrative law judge issued a recommended order, proposing ACC approval of the 2004 Settlement Agreement with two changes related to the PSA. On March 14, 2005, the parties to the 2004 Settlement Agreement jointly filed suggested changes to the recommended order addressing, among other things, the recommended order’s proposed treatment of the PSA. The ACC has scheduled open meetings on March 25 and March 28, 2005 to consider the recommended order and suggested changes. APS cannot predict the outcome of this matter.
Employees
At December 31, 2004, Pinnacle West employed about 7,200 people, including the employees of its subsidiaries. Of these employees, about 6,100 were employees of APS, including employees at jointly-owned generating facilities for which APS serves as the generating facility manager. About 1,100 people were employed by Pinnacle West and its other subsidiaries. Pinnacle West’s principal executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-1000).
Available Information
Pinnacle West makes available free of charge on or through its internet site, (www.pinnaclewest.com) the following filings as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC: its Annual Report on Form 10-K, its Quarterly Reports on Form 10-Q, its Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934.
5
Pinnacle West also has a Corporate Governance webpage. You can access Pinnacle West’s Corporate Governance webpage through its internet site, www.pinnaclewest.com, by clicking on the “About Us” link to the heading “Corporate Commitments.” Pinnacle West posts the following on its Corporate Governance webpage:
Pinnacle West will post any amendments to the Code of Ethics and Ethics Policy and Standards of Business Practices, and any waivers that are required to be disclosed by the rules of either the SEC or the New York Stock Exchange, on its internet site. The information on Pinnacle West’s internet site is not incorporated by reference into this report.
You can request a copy of these documents by contacting Pinnacle West at the following address: Pinnacle West Capital Corporation, Office of the Secretary, Station 9068, P.O. Box 53999, Phoenix, Arizona 85072-3999 (telephone 602-250-3252) .
Forward-Looking Statements
This document contains forward-looking statements based on current expectations, and neither Pinnacle West nor APS assumes any obligation to update these statements or make any further statements on any of these issues, except as required by applicable law. These forward-looking statements are often identified by words such as “estimate,” “predict,” “hope,” “may,” “believe,” “anticipate,” “plan,” “expect,” “require,” “intend,” “assume” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by Pinnacle West or APS. In addition to the “Risk Factors” described in Exhibits 99.31 and 99.32 to this report, these factors include, but are not limited to:
6
REGULATION AND COMPETITION
Retail
The ACC regulates APS’ retail electric rates and its issuance of securities. The ACC must also approve any transfer of APS’ property used to provide retail electric service and approve or receive prior notification of certain transactions between Pinnacle West, APS and their respective affiliates. See Note 3 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for a discussion of the status of electric industry restructuring in Arizona.
The electric utility industry has undergone significant regulatory change in the last few years regarding competition in the sale of electricity and related services. However, many states, including Arizona, have reexamined retail electric competition.
As of January 1, 2001, all of APS’ retail customers were eligible to choose alternate energy suppliers. However, there are currently no active retail competitors offering unbundled energy or other utility services to APS’ customers. As a result, APS cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory. Also, regulatory developments and legal challenges to the Rules have raised considerable uncertainty about the status and pace of retail electric competition and of electric restructuring in Arizona. See “Retail Electric Competition Rules” in Note 3 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for additional information.
7
APS is subject to varying degrees of competition from other investor-owned utilities in Arizona (such as Tucson Electric Power Company and Southwest Gas Corporation) as well as cooperatives, municipalities, electrical districts and similar types of governmental or non-profit organizations (principally Salt River Project). APS also faces competition from low-cost, hydroelectric power and parties that have access to low-priced preferential, federal power and other governmental subsidies. In addition, some customers, particularly industrial and large commercial customers, may own and operate generation facilities to meet their own energy requirements.
Wholesale
The FERC regulates rates for wholesale power sales and transmission services. During 2004, approximately 9.4% of APS’ electric operating revenues resulted from such sales and services. In early 2003, Pinnacle West moved its marketing and trading division to APS for all future marketing and trading activities (existing wholesale contracts remained at Pinnacle West) as a result of the ACC’s Track A Order prohibiting the previously required transfer of APS’ generating assets to Pinnacle West Energy (see “Track A Order” in Note 3 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8).
The marketing and trading division focuses primarily on managing APS’ purchased power and fuel risks in connection with its costs of serving retail customer energy requirements. The division also sells, in the wholesale market, APS and Pinnacle West Energy generation output that is not needed for APS’ Native Load and, in doing so, competes with other utilities, power marketers and independent power producers. Additionally, the marketing and trading division, subject to specified parameters, markets, hedges and trades in electricity, fuels and emissions allowances and credits.
Market-Based Rate Proceeding
On August 11, 2004, Pinnacle West, APS, Pinnacle West Energy and APS Energy Services (collectively, the “Pinnacle West Companies”) submitted to the FERC an update to their three-year market-based rate review, pursuant to the FERC’s order implementing a new generation market power analysis. On December 20, 2004, the FERC issued an order approving the Pinnacle West Companies’ market-based rates for control areas other than those of APS, Public Service Company of New Mexico and Tucson Electric Power Company. With respect to these three control areas, the FERC required that the Pinnacle West Companies submit additional data, and on February 18, 2005, the Pinnacle West Companies made such a filing. To the extent the FERC does not permit the Pinnacle West Companies to make sales at market-based rates in these control areas, the Pinnacle West Companies will still be permitted to make sales at cost-based rates in the three control areas. We cannot currently predict the outcome of this proceeding, but we do not believe that having such sales limited to cost-based rates will have a material adverse effect on our financial position, results of operations or liquidity.
Regional Transmission Organizations
Federal In a December 1999 order, the FERC established characteristics and functions that must be met by utilities in forming and operating RTOs. The characteristics for an acceptable RTO include independence from market participants, operational control over a region large enough to
8
support efficient and nondiscriminatory markets and exclusive authority to maintain short-term reliability. Additionally, in a pending notice of proposed rulemaking, the FERC is considering implementing a standard market design for wholesale markets.
On October 16, 2001, APS and other owners of electric transmission lines in the southwestern U.S. filed with the FERC a request for a declaratory order confirming that their proposal to form WestConnect RTO, LLC would satisfy the FERC’s requirements for the formation of an RTO. On October 10, 2002, the FERC issued an order finding that the WestConnect proposal, if modified to address specified issues, could meet the FERC’s RTO requirements and provide the basic framework for a standard market design for the southwestern U.S. See Arizona Public Service Co., 101 FERC ¶ 61,033, order on reh’g, 101 FERC ¶ 61,350, order on reh’g, 104 FERC ¶ 61,285 (2003). Since that time, APS has been evaluating a phased approach to RTO implementation in the desert Southwest. APS is currently participating with other entities in the southwestern U.S. in a cost/benefit analysis of implementing the WestConnect RTO, the results of which are expected to be completed in 2005.
If APS ultimately joins an RTO, APS could incur increased transmission-related costs and receive reduced transmission service revenues; APS may be required to expand its transmission system according to decisions made by the RTO rather than its internal planning process; and APS may experience other impacts on its operations, cash flows or financial position that will not be quantifiable until the final tariffs and other material terms of the RTO are known.
State The ACC’s retail electric competition Rules require the formation and implementation of an Arizona Independent Scheduling Administrator. The purpose of the AISA is to oversee the application of operating protocols to ensure statewide consistency for transmission access. The AISA is anticipated to be a temporary organization until the implementation of an independent system operator or RTO. APS participated in the creation of the AISA, a not-for-profit entity, and the filing at the FERC for approval of its operating protocols. An ACC proceeding reviewing the AISA is still pending.
BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY
APS was incorporated in 1920 under the laws of the State of Arizona and currently has more than 989,500 customers. APS does not distribute any products. During 2004, no single purchaser or user of energy (other than Pinnacle West) accounted for more than 6.2% of electric revenues. See “Overview – General” and “Regulation and Competition” above for additional background information about APS’ business.
At December 31, 2004, APS employed approximately 6,100 people, including employees at jointly-owned generating facilities for which APS serves as the generating facility manager. APS’ principal executive offices are located at 400 North Fifth Street, P.O. Box 53999, Phoenix, Arizona 85072-3999 (telephone 602-250-1000).
Purchased Power and Generating Fuel
See “Properties – Capacity” in Item 2 for information about APS’ and Pinnacle West’s power plants by fuel types.
9
2004 Energy Mix
Pinnacle West’s consolidated sources of energy during 2004 were: purchased power – 56.9%; coal – 20.8%; nuclear – 13.5%; gas – 8.7%; and other (includes oil, hydro and solar) – 0.1%. In accordance with GAAP, a substantial portion of our purchased power contracts was netted against wholesale sales contracts on the Consolidated Statements of Income. See Note 18 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8.
APS’ sources of energy during 2004 were: purchased power – 62.9%; coal – 21.4%; nuclear – 13.9%; gas – 1.7%; and other (includes oil, hydro and solar) – 0.1%. In accordance with GAAP, a substantial portion of our purchased power contracts was netted against wholesale sales contracts on the Statements of Income. See Note 18 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8.
Coal Supply
Cholla Cholla is a coal-fired power plant located in northeastern Arizona. It is a jointly-owned facility operated by APS. APS purchases most of Cholla’s coal requirements from a coal supplier that mines all of the coal under a long-term lease of coal reserves with the Navajo Nation, the federal government and private landholders. Cholla has sufficient coal under current contracts to ensure a reliable fuel supply through 2007. These contracts include expected requirements for low sulfur coal, which is required for certain limited operating conditions; however, if necessary, low sulfur coal may be purchased on the open market. APS may purchase a portion of Cholla’s coal requirements on the spot market to take advantage of competitive pricing options and to supplement coal required for increased operating capacity. Following expiration of current contracts, APS believes that competitive fuel supply options will exist to ensure the continued operation of Cholla for its useful life, and has evaluated the necessary plant modifications and operational requirements to convert to other fuel sources.
Four Corners Four Corners is a coal-fired power plant located in the northwestern corner of New Mexico. It is a jointly-owned facility operated by APS. APS purchases all of Four Corners’ coal requirements from a supplier with a long-term lease of coal reserves with the Navajo Nation. The Four Corners coal contract runs through July 2016, with options to extend the contract for five to fifteen additional years beyond the current plant site lease expiration in 2017.
Navajo Generating Station The Navajo Generating Station is a coal-fired power plant located in northern Arizona. It is a jointly-owned facility operated by Salt River Project. The Navajo Generating Station’s coal requirements are purchased from a supplier with long-term leases from the Navajo Nation and the Hopi Tribe. The Navajo Generating Station is under contract with its coal supplier through 2011, with options to extend through the current plant site lease expiration in 2019. The Navajo Generating Station lease waives certain taxes through the lease expiration in 2019. Items that may impact the fuel price include lease provisions that allow for a renegotiation of the coal royalty in 2007 and 2017 and a fuel contract requirement for a five-year price review in 2007. In addition, the potential closure of the Mohave Generating Station will impact the cost structure for the Black Mesa – Kayenta Mine complex, and may increase costs to the Navajo Generating Station, which is served by the Kayenta Mine.
See “Legal Proceedings” in Item 3 for information about a lawsuit relating to royalties for coal paid by the participants at the Navajo Generating Station.
10
See “Properties – Capacity” in Item 2 for information about APS’ ownership interests in Cholla, Four Corners and the Navajo Generating Station. See Note 11 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for information regarding APS’ coal mine reclamation obligations.
Natural Gas Supply
See Note 11 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for a discussion of APS’ and Pinnacle West’s natural gas requirements.
Nuclear Fuel Supply
Palo Verde Fuel Cycle Palo Verde is a nuclear power plant located about 50 miles west of Phoenix, Arizona. It is a jointly-owned facility operated by APS. The fuel cycle for Palo Verde is comprised of the following stages:
The Palo Verde participants have contracted for all of Palo Verde’s requirements for uranium concentrates and conversion services through 2008. The Palo Verde participants have also contracted for all of Palo Verde’s enrichment services through 2010 and fuel assembly fabrication services until at least 2015.
Spent Nuclear Fuel and Waste Disposal See “Palo Verde Nuclear Generating Station” in Note 11 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for a discussion of spent nuclear fuel and waste disposal.
Purchased Power Agreements
In addition to its own available generating capacity (see “Properties” in Item 2), APS purchases electricity under various arrangements. One of the most important of these is a long-term contract with Salt River Project. The amount of electricity available to APS is based in large part on customer demand within certain areas now served by APS pursuant to a related territorial agreement. The generating capacity available to APS pursuant to the contract is 350 MW. In 2004, APS received approximately 568,770 MWh of energy under the contract and paid about $54.9 million for capacity availability and energy received. This contract may be canceled by Salt River Project on three years’ notice. By letter dated June 7, 2004, Salt River Project gave notice to APS to reduce capacity by 150 MW effective June 16, 2007. To date, this letter is the only notice Salt River Project has given under the contract. APS may also cancel the contract on five years’ notice, which may be given no earlier than December 31, 2006.
In September 1990, APS entered into a thirty-year seasonal capacity exchange agreement with PacifiCorp. Under this agreement, APS receives electricity from PacifiCorp during the summer
11
peak season (from May 15 to September 15) and APS returns electricity to PacifiCorp during the winter season (from October 15 to February 15). Until 2020, APS and PacifiCorp each has 480 MW of capacity and a related amount of energy available to it under the agreement for its respective seasons. In 2004, APS received approximately 571,392 MWh of energy under the capacity exchange. APS must also make additional offers of energy to PacifiCorp each year through October 31, 2020. Pursuant to this requirement, during 2004, PacifiCorp received offers of 1,095,000 MWh and purchased about 246,275 MWh.
Consistent with the ACC’s Track B Order, APS issued a request for proposals (“RFP”) in March 2003 and, as a result of that RFP, APS entered into contracts with three parties, including Pinnacle West Energy, to meet a portion of APS’ capacity and energy requirements for the years 2003 through 2006. See “Track B Order” in Note 3 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for additional information about the contracts and the Track B Order.
Construction Program
During the years 2002 through 2004, APS incurred approximately $1.4 billion in capital expenditures. APS’ capital expenditures for the years 2005 through 2007 are expected to be primarily for expanding transmission and distribution capabilities to meet growing customer needs, for upgrading existing utility property and for environmental purposes. APS’ capital expenditures were approximately $484 million in 2004. APS’ capital expenditures, including expenditures for environmental control facilities, for the years 2005 through 2007 have been estimated as follows (dollars in millions):
The above amounts exclude capitalized interest costs and include capitalized property taxes and approximately $30 million per year for nuclear fuel. The estimate for 2005 includes about $190 million for APS’ planned acquisition of the Sundance Plant. See “Request for Proposals and Asset Purchase Agreement” in Note 3 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for a discussion of the asset purchase agreement between APS and PPL Sundance. APS conducts a continuing review of its construction program.
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Needs and Resources by Company” in Item 7 for additional information about APS’ construction programs.
12
Environmental Matters
EPA Environmental Regulation
Regional Haze Rules On April 22, 1999, the EPA announced final regional haze rules. These regulations require states to submit implementation plans by 2008 to eliminate all man-made emissions causing visibility impairment in certain specified areas, including Class I Areas in the Colorado Plateau, and to consider and potentially apply the best available retrofit technology (“BART”) for major stationary sources.
The rules allow nine western states and tribes to follow an alternate implementation plan and schedule for the Class I Areas. This alternate implementation plan is known as the Annex Rule. Five western states, including Arizona, have submitted proposed State Implementation Plans to the EPA to implement the Annex Rule.
On February 18, 2005, the U.S. Court of Appeals for the District of Columbia granted a petition for review of the Annex Rule, filed by the Center for Energy and Economic Development (CEED). Center for Energy and Economic Development v. the EPA, No. 03-1222 (D.C. Cir.). APS, Phelps Dodge Corporation, and Environmental Defense were intervenors in the litigation in support of the EPA and the Annex Rule. Although the Court concluded that the EPA has the authority to promulgate a BART alternative, the Court ruled that the EPA must first conduct a BART analysis of eligible sources to demonstrate that the alternate plan would achieve greater reductions than BART. At this time, the EPA’s response to theCEED decision is uncertain. The Company cannot currently predict the outcome of this matter.
Mercury On March 15, 2005, the EPA issued the Clean Air Mercury Rule to regulate mercury emissions from coal-fired power plants. This rule establishes performance standards limiting mercury emissions from coal-fired power plants and establishes a two phased market-based trading program. Under the trading program, the EPA has assigned each state a "budget" for reducing coal-fired power plant mercury emissions, and each state must submit to the EPA a plan detailing how it will meet its "budget." In the first phase of the program, beginning in 2010, mercury emissions will be reduced from a total of 48 tons per year to 38 tons. In 2018, mercury emissions will be further reduced to 15 tons. APS is currently evaluating the potential impact of this rule.
Federal Implementation Plan In September 1999, the EPA proposed a FIP to set air quality standards at certain power plants, including the Navajo Generating Station and Four Corners. The FIP is similar to current Arizona regulation of the Navajo Generating Station and New Mexico regulation of Four Corners, with minor modifications. APS does not currently expect the FIP to have a material adverse effect on its financial position, results of operations or liquidity.
Superfund Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often jointly and severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA
13
considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona. APS has facilities that are within this superfund site. APS and Pinnacle West have agreed with the EPA to perform certain investigative activities of the APS facilities within OU3. Because the investigation has not yet been completed and ultimate remediation requirements are not yet finalized, neither APS nor Pinnacle West can currently estimate the expenditures which may be required.
Manufactured Gas Plant Sites APS is currently investigating properties, which it now owns or which were previously owned by it or its corporate predecessors, that were at one time sites of, or sites associated with, manufactured gas plants. APS is taking action to voluntarily remediate these sites. APS does not expect these matters to have a material adverse effect on its financial position, results of operations or liquidity.
Navajo Nation Environmental Issues
Four Corners and the Navajo Generating Station are located on the Navajo Reservation and are held under easements granted by the federal government as well as leases from the Navajo Nation. APS is the Four Corners operating agent. APS owns all of Four Corners Units 1, 2 and 3, and a 15% interest in Four Corners Units 4 and 5. APS owns a 14% interest in Navajo Generating Station Units 1, 2 and 3.
In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act and the Navajo Nation Pesticide Act (collectively, the Navajo Acts). The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water and pesticide activities, including those activities that occur at Four Corners and the Navajo Generating Station. On October 17, 1995, the Four Corners participants and the Navajo Generating Station participants each filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, challenging the applicability of the Navajo Nation as to Four Corners and Navajo Generating Station. The Court has stayed these proceedings pursuant to a request by the parties, and the parties are seeking to negotiate a settlement. APS cannot currently predict the outcome of this matter.
In February 1998, the EPA issued regulations identifying those Clean Air Act provisions for which it is appropriate to treat Indian tribes in the same manner as states. The EPA has announced that it has not yet determined whether the Clean Air Act would supersede pre-existing binding agreements between the Navajo Nation and the Four Corners participants and the Navajo Generating Station participants that limit the Navajo Nation’s environmental regulatory authority over the Navajo Generating Station and Four Corners. APS believes that the Clean Air Act does not supersede these pre-existing agreements. The parties have reached tentative agreement on a resolution of the Clean Air Act issues. If such an agreement is executed by the parties and approved by the EPA, APS would dismiss the pending litigation to the extent the claims relate to the Clean Air Act. APS cannot currently predict the outcome of this matter.
In April 2000, the Navajo Tribal Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. APS believes the regulations fail to recognize that the Navajo Nation did not intend to assert jurisdiction over Four Corners and the Navajo Generating Station. On July 12, 2000, the Four Corners participants and the Navajo Generating Station participants each filed a petition with the Navajo Supreme Court for review of the
14
operating permit regulations. Those proceedings have been stayed, pending the settlement negotiations mentioned above. APS cannot currently predict the outcome of this matter.
Water Supply
Assured supplies of water are important for APS’ and Pinnacle West Energy’s generating plants. At the present time, APS and Pinnacle West Energy have adequate water to meet their needs. However, conflicting claims to limited amounts of water in the southwestern United States have resulted in numerous court actions.
Both groundwater and surface water in areas important to APS’ operations have been the subject of inquiries, claims and legal proceedings, which will require a number of years to resolve. APS is one of a number of parties in a proceeding before a state court in New Mexico to adjudicate rights to a stream system from which water for Four Corners is derived. (State of New Mexico, in the relation of S.E. Reynolds, State Engineer vs. United States of America, City of Farmington, Utah International, Inc., et al., San Juan County, New Mexico, District Court No. 75-184). An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for a then-agreed upon cost, sufficient water from its allocation to offset the loss.
A summons served on APS in early 1986 required all water claimants in the Lower Gila River Watershed in Arizona to assert any claims to water on or before January 20, 1987, in an action pending in Maricopa County, Arizona, Superior Court. (In re The General Adjudication of All Rights to Use Water in the Gila River System and Source, Supreme Court Nos. WC-79-0001 through WC 79-0004 (Consolidated) [WC-1, WC-2, WC-3 and WC-4 (Consolidated)], Maricopa County Nos. W-1, W-2, W-3 and W-4 (Consolidated)). Palo Verde is located within the geographic area subject to the summons. APS’ rights and the rights of the Palo Verde participants to the use of groundwater and effluent at Palo Verde are potentially at issue in this action. As project manager of Palo Verde, APS filed claims that dispute the court’s jurisdiction over the Palo Verde participants’ groundwater rights and their contractual rights to effluent relating to Palo Verde. Alternatively, APS seeks confirmation of such rights. Three of APS’ other power plants and two of Pinnacle West Energy’s power plants are also located within the geographic area subject to the summons. APS’ claims dispute the court’s jurisdiction over its groundwater rights with respect to these plants. Alternatively, APS seeks confirmation of such rights. In November 1999, the Arizona Supreme Court issued a decision confirming that certain groundwater rights may be available to the federal government and Indian tribes. In addition, in September 2000, the Arizona Supreme Court issued a decision affirming the lower court’s criteria for resolving groundwater claims. Litigation on both of these issues will continue in the trial court. No trial date concerning APS’ water rights claims has been set in this matter.
APS has also filed claims to water in the Little Colorado River Watershed in Arizona in an action pending in the Apache County, Arizona, Superior Court. (In re The General Adjudication of All Rights to Use Water in the Little Colorado River System and Source, Supreme Court No. WC-79-0006 WC-6, Apache County No. 6417). APS’ groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and is therefore potentially at issue in the case. APS’ claims dispute the court’s jurisdiction over its groundwater rights. Alternatively, APS seeks confirmation of such rights. A number of parties are in the process of settlement negotiations with respect to certain claims in this matter. Other claims have been identified as ready for litigation in
15
motions filed with the court. No trial date concerning APS’ water rights claims has been set in this matter.
Although the above matters remain subject to further evaluation, Pinnacle West expects that the described litigation will not have a material adverse impact on its financial position, results of operations or liquidity.
The Four Corners region, in which Four Corners is located, has been experiencing drought conditions that may affect the water supply for the plants if adequate moisture is not received in the watershed that supplies the area. APS is continuing to work with area stakeholders to implement agreements to minimize the effect, if any, on operations of the plant for 2005 and later years. The effect of the drought cannot be fully assessed at this time, and APS cannot predict the ultimate outcome, if any, of the drought or whether the drought will adversely affect the amount of power available, or the price thereof, from Four Corners.
BUSINESS OF PINNACLE WEST ENERGY CORPORATION
Pinnacle West Energy was incorporated in 1999 under the laws of the State of Arizona and is engaged principally in the operation of unregulated generating plants. Pinnacle West Energy had approximately 100 employees as of December 31, 2004. Pinnacle West Energy’s principal offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-4145).
See “Liquidity and Capital Resources” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of Pinnacle West Energy’s capital requirements.
Pinnacle West Energy owns the PWEC Dedicated Assets as well as an interest in Silverhawk. The PWEC Dedicated Assets were built as a result of what APS believed was a regulatory restriction against APS’ construction of additional plants and based on the requirement in the 1999 Settlement Agreement that APS transfer its generation assets. As discussed under “APS General Rate Case; 2004 Settlement Agreement” in Note 3 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8, as part of the proposed settlement of APS’ general rate case, APS would acquire the PWEC Dedicated Assets from Pinnacle West Energy. Silverhawk, which is Pinnacle West Energy’s only power plant not included in the PWEC Dedicated Assets, is a 570 MW combined cycle power plant located 20 miles north of Las Vegas, Nevada in which Pinnacle West Energy has a 75% ownership interest. See “Properties” in Item 2 for a summary of the generating plants owned by Pinnacle West Energy.
At December 31, 2004, Pinnacle West Energy had total assets of $1.3 billion, of which $1.0 billion related to the PWEC Dedicated Assets. Pinnacle West Energy had a pretax loss of $47 million in 2004, a net loss of $1 million in 2003 and a net loss of $19 million in 2002. Income taxes related to Pinnacle West Energy were recorded by Pinnacle West in 2004.
BUSINESS OF APS ENERGY SERVICES COMPANY, INC.
APS Energy Services was incorporated in 1998 under the laws of the State of Arizona and provides competitive commodity-related energy services (such as direct access commodity contracts, energy procurement and energy supply consultation) and energy-related products and services (such as energy master planning, energy use consultation and facility audits, cogeneration analysis and installation and project management) to commercial, industrial and institutional retail customers in
16
the western United States. APS Energy Services had approximately 100 employees as of December 31, 2004. APS Energy Services’ principal offices are located at 400 East Van Buren Street, Phoenix, Arizona 85004 (telephone 602-250-5000).
APS Energy Services had net income of $3 million in 2004, net income of $16 million in 2003, and pretax income of $28 million in 2002. Income taxes related to APS Energy Services were recorded by Pinnacle West prior to 2003. At December 31, 2004, APS Energy Services had total assets of $77 million.
BUSINESS OF SUNCOR DEVELOPMENT COMPANY
SunCor was incorporated in 1965 under the laws of the State of Arizona and is a developer of residential, commercial and industrial real estate projects in Arizona, Idaho, New Mexico and Utah. The principal executive offices of SunCor are located at 80 East Rio Salado Parkway, Suite 410, Tempe, Arizona 85281 (telephone 480-317-6800). SunCor and its subsidiaries had approximately 800 employees at December 31, 2004.
At December 31, 2004, SunCor had total assets of about $464 million. SunCor’s assets consist primarily of land with improvements, commercial buildings, golf courses and other real estate investments. SunCor intends to continue its focus on real estate development of master-planned communities, mixed-use residential, commercial, office and industrial projects.
SunCor projects under development include seven master-planned communities and several commercial projects. The commercial projects and four of the master-planned communities are in Arizona. Other master-planned communities are located near St. George, Utah, Boise, Idaho and Santa Fe, New Mexico.
SunCor has implemented an accelerated asset sales program for 2003 through 2005. As a result of this program, SunCor expects to have net income of approximately $50 million in 2005. SunCor also expects to make a cash distribution of approximately $80 million to $100 million to the parent in 2005.
For the past three years, SunCor’s operating revenues were approximately: $360 million in 2004; $362 million in 2003; and $201 million in 2002. SunCor’s net income was approximately $45 million in 2004; $56 million in 2003; and $19 million in 2002. Certain components of SunCor’s real estate sales activities, which are included in the real estate segment, are required to be reported as discontinued operations on Pinnacle West’s Consolidated Statements of Income in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” See Note 22 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8.
See Note 6 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for information regarding SunCor’s long-term debt and “Liquidity and Capital Resources” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of SunCor’s capital requirements.
BUSINESS OF EL DORADO INVESTMENT COMPANY
El Dorado was incorporated in 1983 under the laws of the State of Arizona. El Dorado owns minority interests in several energy-related investments and Arizona community-based ventures. El
17
Dorado’s short-term goal is to prudently realize the value of its existing investments. On a long-term basis, Pinnacle West may use El Dorado, when appropriate, for investments that are strategic to the business of generating, distributing and marketing electricity. El Dorado’s offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-3517).
El Dorado had pretax income of $40 million in 2004, pretax income of $7 million in 2003, and a pretax loss of $55 million in 2002. Pinnacle West records income taxes related to El Dorado. El Dorado sold its investment in NAC on November 18, 2004, which resulted in a pre-tax gain of $4 million and is classified as discontinued operations in 2004. All related revenue and expenses for NAC have been reclassified to discontinued operations for the years ended December 31, 2003 and 2002 (see Note 22 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8). In addition, the year ended 2004 includes a $35 million gain ($21 million after tax) related to the sale of El Dorado’s limited partnership interest in the Phoenix Suns. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for additional information. At December 31, 2004, El Dorado had total assets of $23 million.
18
ITEM 2. PROPERTIES
Capacity
APS’ and Pinnacle West Energy’s generating facilities are described below. For APS’ plants, the “net accredited capacities” are reported, consistent with industry practice for regulated utilities. For Pinnacle West Energy, the “permitted capacities” are reported, consistent with industry practice for unregulated plants.
APS – Net Accredited Capacity
APS’ present generating facilities have net accredited capacities as follows:
19
Reserve Margin
APS’ 2004 peak one-hour demand on its electric system was recorded on August 11, 2004 at 6,402,100 kW, compared to the 2003 peak of 6,332,400 kW recorded on July 14, 2003. Taking into account additional capacity then available to APS under long-term purchase power contracts as well as APS’ and Pinnacle West Energy’s generating capacity, APS’ capability of meeting system demand on August 11, 2004, amounted to 6,388,600 kW, for an installed reserve margin of negative 0.3%. The power actually available to APS from its resources fluctuates from time to time due in part to planned and unplanned plant and transmission outages and technical problems. The available capacity from sources actually operable at the time of the 2004 peak amounted to 3,570,600 kW, for a margin of negative 52.6%. Firm purchases totaling 4,187,000 kW, including short-term seasonal purchases and unit contingent purchases, were in place at the time of the peak, ensuring the ability to meet the load requirement with an actual reserve margin of 6.9 %.
See “Business of Arizona Public Service Company – Purchased Power and Generating Fuel – Purchased Power Agreements” in Item 1 for information about certain of APS’ long-term power agreements.
Plant Sites Leased from Navajo Nation
The Navajo Generating Station and Four Corners are located on land held under easements from the federal government and also under leases from the Navajo Nation. These are long-term agreements with options to extend, and APS does not believe that the risks with respect to enforcement of these easements and leases are material. The majority of coal contracted for use in these plants and certain associated transmission lines are also located on Indian reservations. See “Business of Arizona Public Service Company – Purchased Power and Generating Fuel – Coal Supply” in Item 1.
Palo Verde Nuclear Generating Station
Regulatory
Operation of each of the three Palo Verde units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987. The full power operating licenses, each valid for a period of approximately 40 years, authorize APS, as operating agent for Palo Verde, to operate the three Palo Verde units at full power.
Nuclear Decommissioning Costs
The NRC rules on financial assurance requirements for the decommissioning of nuclear power plants provide that a licensee may use a trust as the exclusive financial assurance mechanism if the licensee recovers estimated total decommissioning costs through cost-of-service rates or through a “non-bypassable charge.” The “non-bypassable systems benefits” charge is the charge that the ACC has approved for APS’ recovery of certain types of costs, including costs for low income programs, demand side management, consumer education, environmental, renewables, etc. “Non-bypassable” means that if a customer chooses to take energy from an “energy service provider” other than APS, the customer will still have to pay this charge as part of the customer’s APS electric bill.
20
Other mechanisms are prescribed, including prepayment, if the requirements for exclusive reliance on an external sinking fund mechanism are not met. APS currently relies on an external sinking fund mechanism to meet the NRC financial assurance requirements for its interests in Palo Verde Units 1, 2 and 3. The decommissioning costs of Palo Verde Units 1, 2 and 3 are currently included in APS’ ACC jurisdictional rates. The Rules provide that decommissioning costs are recoverable through a non-bypassable “system benefits” charge, which would allow APS to maintain its external sinking fund mechanism. See Note 12 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for additional information about APS’ nuclear decommissioning costs.
Palo Verde Liability and Insurance Matters
See “Palo Verde Nuclear Generating Station” in Note 11 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for a discussion of the insurance maintained by the Palo Verde participants, including APS, for Palo Verde.
Property Not Held in Fee or Subject to Encumbrances
Jointly-Owned Facilities
APS shares ownership of some of its generating and transmission facilities with other companies. Pinnacle West Energy shares ownership of its Silverhawk plant. The following table shows APS’ and Pinnacle West Energy’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2004:
21
Palo Verde Leases
In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale leaseback transactions. APS accounts for these leases as operating leases. The leases, which have terms of 29.5 years, contain options to renew the leases for two additional years and to purchase the property for fair market value at the end of the lease terms. See Notes 9 and 20 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for additional information regarding the Palo Verde Unit 2 sale leaseback transactions.
Transmission Access
APS’ transmission facilities consist of approximately 5,589 pole miles of overhead lines and approximately 37 miles of underground lines, 5,457 miles of which are located within the State of Arizona. APS’ distribution facilities consist of approximately 12,211 pole miles of overhead lines and approximately 13,727 miles of underground lines, all of which are located within the State of Arizona.
Other Information Regarding Our Properties
See “Business of Arizona Public Service Company – Environmental Matters” and “Water Supply” in Item 1 with respect to matters having a possible impact on the operation of certain of APS’ and Pinnacle West Energy’s power plants.
See “Business of Arizona Public Service Company – Construction Program” in Item 1 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in Item 7 for a discussion of APS’ and Pinnacle West Energy’s construction programs.
Information Regarding SunCor’s Properties
See “Business of SunCor Development Company” in Item 1 for information regarding SunCor’s properties. Substantially all of SunCor’s debt is collateralized by interests in certain real property.
22
23
ITEM 3. LEGAL PROCEEDINGS
See “Business of Arizona Public Service Company – Environmental Matters” and “– Water Supply” in Item 1 with regard to pending or threatened litigation and other disputes. See Note 3 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for a discussion of the Rules, the Track A Order and related litigation.
See Note 11 of Notes to the Pinnacle West Consolidated Financial Statements in Item 8 with regard to a lawsuit against APS and the other Navajo Generating Station participants and for information relating to the FERC proceedings on California energy market issues.
ITEM 4. SUBMISSION OF MATTERS TO AVOTE OF SECURITY HOLDERS
Not applicable.
24
SUPPLEMENTAL ITEM.EXECUTIVE OFFICERS OF PINNACLE WEST
Pinnacle West’s executive officers are as follows:
The executive officers of Pinnacle West are elected no less often than annually and may be removed by the Board of Directors at any time. The terms served by the named officers in their current positions and the principal occupations (in addition to those stated in the table) of such officers for the past five years have been as follows:
25
Mr. Post was elected Chairman of the Board effective February 2001, and Chief Executive Officer effective February 1999. He has served as an officer of Pinnacle West since 1995 in the following capacities: from August 1999 to February 2001 as President; from February 1997 to February 1999 as President; and from June 1995 to February 1997 as Executive Vice President. Mr. Post is also Chairman of the Board (since February 2001) of APS. He was President of APS from February 1997 until October 1998 and he was Chief Executive Officer from February 1997 until October 2002. Mr. Post is also a director of APS, Pinnacle West Energy and Phelps Dodge Corporation.
Mr. Davis was elected President effective February 2001 and Chief Operating Officer effective September 2003. Prior to that time he was Chief Operating Officer and Executive Vice President of Pinnacle West (April 2000 – February 2001) and Executive Vice President, Commercial Operations of APS (September 1996 – October 1998). Mr. Davis is also President of APS (since October 1998) and Chief Executive Officer of APS (since October 2002). He is a director of APS and Pinnacle West Energy.
Mr. Brandt was elected to his present position in September 2003 and was Senior Vice President and Chief Financial Officer (December 2002 – September 2003). Prior to that time, he was Senior Vice President and Chief Financial Officer of Ameren Corporation (diversified energy services company). Mr. Brandt was elected Executive Vice President and Chief Financial Officer of APS in September 2003. He was also Senior Vice President and Chief Financial Officer of APS (January 2003 – September 2003).
Mr. Flores was elected to his present position in September 2003. Prior to that time, he was Executive Vice President, Corporate Business Services of Pinnacle West (July 1999 – September 2003). He was also Executive Vice President, Corporate Business Services of APS (October 1998 – July 1999).
Mr. Froggatt was elected to his present position in October 2002. Prior to that time, he was Vice President and Controller of Pinnacle West (August 1999 – October 2002), Controller of Pinnacle West (July 1999 – August 1999) and Controller of APS (July 1997 – July 1999).
Ms. Gomez was elected to her present position in February 2004. Prior to that time, she was Treasurer (August 1999 – February 2004) and Manager, Treasury Operations of APS (1997 – 1999). She was also elected Treasurer of APS in October 1999 and Vice President of APS in February 2004.
Mr. Levine was elected Executive Vice President of APS in July 1999 and President and Chief Executive Officer of Pinnacle West Energy in January 2003. Prior to that time, he was Senior Vice President, Nuclear Generation of APS (September 1996 – July 1999).
Ms. Loftin was elected Vice President and General Counsel in July 1999 and Secretary in October 2002. She was also elected Vice President and General Counsel of APS in July 1999 and Secretary of APS in October 2002.
Mr. Robinson was elected to his present position in September 2003. Prior to that time, he was Vice President, Finance and Planning of APS (October 2002 – September 2003), Vice President, Regulation and Planning of Pinnacle West (June 2001 – October 2002) and Director, Accounting, Regulation and Planning of Pinnacle West (prior to June 2001).
Mr. Wheeler was elected to his present position in September 2003. Prior to that time, he was Senior Vice President, Regulation, System Planning and Operations of APS (October 2002 – September 2003) and Senior Vice President, Transmission, Regulation and Planning of Pinnacle West and APS (June 2001 – October 2002). Prior to that time he was a partner with Snell & Wilmer L.L.P.
26
PART II
ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATEDSTOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Pinnacle West’s common stock is publicly held and is traded on the New York and Pacific Stock Exchanges. At the close of business on March 14, 2005, Pinnacle West’s common stock was held of record by approximately 34,248 shareholders.
QUARTERLY STOCK PRICES AND DIVIDENDS PAID PER SHARESTOCK SYMBOL: PNW
APS’ common stock is wholly-owned by Pinnacle West and is not listed for trading on any stock exchange. As a result, there is no established public trading market for APS’ common stock.
The chart below sets forth the dividends declared on APS’ common stock for each of the four quarters for 2004 and 2003.
Common Stock Dividends(Dollars in Thousands)
The sole holder of APS’ common stock, Pinnacle West, is entitled to dividends when and as declared out of funds legally available therefor. As of December 31, 2004, APS did not have any outstanding preferred stock.
Pinnacle West did not purchase any of its common stock during the fourth quarter of 2004.
27
ITEM 6. SELECTED FINANCIAL DATA
PINNACLE WEST CAPITAL CORPORATIONSELECTED CONSOLIDATED FINANCIAL DATA
28
SELECTED FINANCIAL DATAARIZONA PUBLIC SERVICE COMPANY
29
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSISOF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with Pinnacle West’s Consolidated Financial Statements and Arizona Public Service Company’s Financial Statements and the related Notes that appear in Item 8 of this report.
Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. Through its marketing and trading division, APS also generates, sells and delivers electricity to wholesale customers in the western United States. APS has historically accounted for a substantial part of our revenues and earnings. Customer growth in APS’ service territory is about three times the national average and remains a fundamental driver of our revenues and earnings.
Pinnacle West Energy is our unregulated generation subsidiary. We formed Pinnacle West Energy in 1999 as a result of the ACC’s requirement that APS transfer all of its competitive assets and services to an affiliate or to a third party by the end of 2002. We planned to transfer APS’ generation assets to Pinnacle West Energy. Additionally, Pinnacle West Energy constructed several power plants to meet growing energy needs (1790 MW in Arizona and 570 MW in Nevada). In September 2002, the ACC issued the Track A Order, which prohibited APS from transferring its generation assets to Pinnacle West Energy. As a result of the Track A Order, APS, through its general rate case currently pending before the ACC, is seeking to transfer the plants built by Pinnacle West Energy in Arizona to APS to unite the Arizona generation under one common owner, as originally intended. We refer to these plants as the PWEC Dedicated Assets.
SunCor, our real estate development subsidiary, has been and is expected to be an important source of earnings and cash flow, particularly during the years 2003 through 2005 due to accelerated asset sales activity.
Our subsidiary, APS Energy Services, provides competitive commodity-related energy services and energy-related products and services to commercial and industrial retail customers in the western United States.
El Dorado, our investment subsidiary, sold its investment in NAC on November 18, 2004, which resulted in a pretax gain of $4 million and the classification of NAC as discontinued operations in 2004. In addition, the year ended December 31, 2004 includes a $35 million gain ($21 million after tax) related to the sale of El Dorado’s limited partnership interest in the Phoenix Suns.
We continue to focus on solid operational performance in our electricity generation and delivery activities. In the generation area, 2004 represented the thirteenth consecutive year Palo Verde was the largest power producer in the United States. In the delivery area, we focus on superior reliability and customer satisfaction while expanding our transmission and distribution system to
30
meet growth and sustain reliability. We plan to expand long-term resources to meet our retail customers’ growing electricity needs.
We believe APS’ general rate case pending before the ACC is the key issue affecting our outlook. As discussed in greater detail in Note 3, on August 18, 2004, a substantial majority of the parties to the rate case, including APS, the ACC staff, the Arizona Residential Utility Consumer Office, other customer and advocacy groups, and merchant power plant intervenors entered into the 2004 Settlement Agreement, which proposes terms under which the rate case would be settled. Neither Pinnacle West nor APS is able to predict whether the ACC will approve the 2004 Settlement Agreement as proposed.
Other factors affecting our past and future financial results include customer growth; purchased power and fuel costs; operations and maintenance expenses, including those relating to plant and transmission outages; weather variations; depreciation and amortization expenses, which are affected by net additions to utility plant and other property and changes in regulatory asset amortization; and the performance of our subsidiaries.
EARNINGS CONTRIBUTIONS BY BUSINESS SEGMENTS
We have three principal business segments (determined by services and the regulatory environment):
The following table summarizes income from continuing operations by segment and net income for the years ended December 31, 2004, 2003 and 2002 (dollars in millions):
31
See Note 17 for additional financial information regarding our business segments.
PINNACLE WEST CONSOLIDATED – RESULTS OF OPERATIONS
Throughout the following explanations of our results of operations, we refer to “gross margin.” With respect to our regulated electricity segment and our marketing and trading segment, gross margin refers to electric operating revenues less purchased power and fuel costs. “Gross margin” is a “non-GAAP financial measure,” as defined in accordance with SEC rules. “Operating margin” (a GAAP financial measure) plus “other operating expenses,” as disclosed in Note 17, is equal to gross margin. We view gross margin as an important performance measure of the core profitability of our operations. This measure is a key component of our internal financial reporting and is used by our management in analyzing our business segments. We believe that investors benefit from having access to the same financial measures that our management uses. In addition, we have reclassified certain prior period amounts to conform to our current period presentation.
2004 Compared with 2003
Our consolidated net income for the twelve months ended December 31, 2004 was $243 million compared with $241 million for the prior-year period. The $2 million increase in the period-to-period comparison reflected the following changes in earnings by segment:
32
33
Additional details on the major factors that increased (decreased) income from continuing operations and net income are contained in the following table (dollars in millions).
The increase in net costs (primarily interest expense, depreciation and operations and maintenance expense, net of gross margin contributions) related to new power plants placed in service in mid-2003 and mid-2004 by Pinnacle West Energy totaled approximately $26 million after income taxes in the twelve months ended December 31, 2004 compared with the prior-year period.
34
Regulated Electricity Segment Revenues
Regulated electricity segment revenues were $57 million higher for the twelve months ended December 31, 2004 compared with the prior-year period primarily as a result of:
Marketing and Trading Segment Revenues
Marketing and trading segment revenues were $70 million higher for the twelve months ended December 31, 2004 compared with the prior-year period primarily as a result of:
Other Revenues
Other revenues were $15 million higher for the twelve months ended December 31, 2004 compared with the prior-year period primarily due to higher non-commodity revenues at APS Energy Services.
2003 Compared with 2002
Our consolidated net income for the year ended December 31, 2003 was $241 million compared with $149 million for the prior year. The 2003 net income included $15 million of after-tax income from discontinued operations related to NAC and SunCor. The 2002 net income included a $21 million after-tax loss from discontinued operations related to NAC and SunCor (see Note 22). The 2002 net income also included a $66 million after-tax charge for the cumulative effect of a change in accounting for trading activities due to the adoption of EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (see Note 18). Excluding the discontinued operations and
35
the accounting change, the $11 million decrease in the period-to-period comparison reflects the following changes in earnings by segment:
36
Additional details on the major factors that increased (decreased) income from continuing operations and net income for the year ended December 31, 2003 compared with the prior year are contained in the following table (dollars in millions).
37
The increase in operating and interest costs related to new power plants placed in service by Pinnacle West Energy, net of purchased power savings and increased gross margin from generation sales other than Native Load, totaled approximately $30 million after income taxes in the year ended December 31, 2003 compared with the prior-year period.
Regulated electricity segment revenues were $88 million higher in the year ended December 31, 2003 compared with the prior year, primarily as a result of:
Marketing and trading segment revenues were $105 million higher in the year ended December 31, 2003 compared with the prior year, primarily as a result of:
38
Real Estate Segment Revenues
Real estate segment revenues were $161 million higher in the year ended December 31, 2003 compared with the prior year primarily as a result of increased asset, land and home sales related to SunCor’s effort to accelerate asset sales.
LIQUIDITY AND CAPITAL RESOURCES
Capital Needs and Resources – Pinnacle West Consolidated
Capital Expenditure Requirements
The following table summarizes the actual capital expenditures for the year ended December 31, 2004 and estimated capital expenditures for the next three years.
CAPITAL EXPENDITURES(dollars in millions)
Delivery capital expenditures are comprised of T&D infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and facility costs. Examples of the types of projects included in the forecast include T&D lines and substations, line extensions to new residential and commercial developments and upgrades to customer information systems. Major transmission projects are driven by strong regional customer growth.
39
Generation capital expenditures are comprised of various improvements to APS’ existing fossil and nuclear plants, the acquisition of the Sundance Plant and the replacement of Palo Verde steam generators (see below). Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment such as turbines, boilers and environmental equipment. Generation also includes nuclear fuel expenditures of approximately $30 million annually for 2005 to 2007.
Replacement of the steam generators in Palo Verde Unit 2 was completed during the fall outage of 2003 at a cost to APS of approximately $70 million. The Palo Verde owners have approved the manufacture of two additional sets of steam generators. These generators will be installed in Unit 1 (scheduled completion in the fall of 2005) and Unit 3 (scheduled completion in the fall of 2007). Our portion of steam generator expenditures for Units 1 and 3 is approximately $140 million, which will be spent through 2008. In 2005 through 2007, approximately $95 million of the costs for steam generator replacements at Units 1 and 3 are included in the generation capital expenditures table above and will be funded with internally-generated cash or external financings.
Contractual Obligations
The following table summarizes Pinnacle West’s consolidated contractual requirements as of December 31, 2004 (dollars in millions):
40
Off-Balance Sheet Arrangements
In 1986, APS entered into agreements with three separate VIE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. See Note 9 for further information about the sale leaseback transactions. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them.
APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2004, APS would have been required to assume approximately $250 million of debt and pay the equity participants approximately $192 million.
In the first quarter of 2004, we adopted FIN No. 46R, “Consolidation of Variable Interest Entities” for all non-SPE contractual arrangements. SunCor has certain land development arrangements that are required to be consolidated under FIN No. 46R. The assets and non-controlling interests reflected in our Consolidated Balance Sheets related to these arrangements were approximately $34 million at December 31, 2004.
Guarantees and Letters of Credit
We and certain of our subsidiaries have issued guarantees and letters of credit in support of our unregulated businesses. We have also obtained surety bonds on behalf of APS Energy Services. We have not recorded any liability on our Consolidated Balance Sheets with respect to these obligations. We generally provide indemnifications related to liabilities arising from or related to certain of our agreements, with limited exceptions depending on the particular agreement. See Note 21 for additional information regarding guarantees and letters of credit.
Credit Ratings
The ratings of securities of Pinnacle West and APS as of March 15, 2005 are shown below and are considered to be “investment-grade” ratings. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies, if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’ securities and serve to increase those companies’ cost of and access
41
to capital. It may also require additional collateral related to certain derivative instruments (see Note 18).
APS no longer has any senior secured debt. See “Capital Needs and Resources – By Company – APS” below for a discussion of the termination of APS’ mortgage and deed of trust.
Debt Provisions
Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include a debt-to-total-capitalization ratio and an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet these and other significant covenant requirements. These covenants require that the ratio of debt to total capitalization cannot exceed 65% for the Company and for APS. At December 31, 2004, the ratio was approximately 53% for Pinnacle West and 54% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for each of the Company and APS. Based on 2004 results, the coverages were approximately 4 times for the Company and 4 times for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants.
Neither Pinnacle West’s nor APS’ financing agreements contain “ratings triggers” that would result in an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a ratings downgrade, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements.
All of Pinnacle West’s bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under other agreements. All of APS’ bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under other agreements. Pinnacle West’s and APS’ credit agreements generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in financial condition or financial prospects, except that Pinnacle West and APS do not have a material adverse change restriction for revolver borrowings equal to outstanding commercial paper amounts.
42
See Note 6 for further discussions.
Capital Needs and Resources — By Company
Pinnacle West (Parent Company)
Our primary cash needs are for dividends to our shareholders; interest payments and optional and mandatory repayments of principal on our long-term debt (see the table above for our contractual requirements, including our debt repayment obligations, but excluding optional repayments). On October 20, 2004, our Board of Directors increased the common stock dividend to an indicated annual rate of $1.90 per share from $1.80 per share, effective with the December 1, 2004 dividend payment. The level of our common dividends and future dividend growth will be dependent on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.
Our primary sources of cash are dividends from APS, external financings and cash distributions from our other subsidiaries, primarily SunCor. For the years 2002 through 2004, total dividends from APS were $510 million and total cash distributions from SunCor were $206 million. For the year ended December 31, 2004, dividends from APS were approximately $170 million and distributions from SunCor were approximately $85 million. We expect SunCor to make cash distributions to the parent company of approximately $80 to $100 million in 2005 based on anticipated asset sales activities. As discussed in Note 3 under “ACC Financing Orders,” APS must maintain a common equity ratio of at least 40% and may not pay common dividends if the payment would reduce its common equity below that threshold. As defined in the Financing Order, common equity ratio is common equity divided by common equity plus long-term debt, including current maturities of long-term debt. At December 31, 2004, APS’ common equity ratio as defined was approximately 45%.
On February 2, 2004, we used proceeds from the $165 million Floating Rate Notes issued on November 12, 2003 and short-term borrowings to pay down the maturing $215 million 4.5% Senior Notes due 2004.
At December 31, 2004, the parent company’s outstanding long-term debt, including current maturities, was $468 million. In October 2004, we replaced two separate revolving credit facilities (with collective borrowing capacity of $275 million) with a $300 million revolving credit facility that terminates in October 2007. This line of credit is available to support the issuance of up to $250 million in commercial paper or to be used as bank borrowings, including up to $100 million for issuances of letters of credit. At December 31, 2004, we had no commercial paper or short-term borrowings outstanding. We ended 2004 in an invested position.
Pinnacle West sponsors a qualified pension plan for the employees of Pinnacle West and our subsidiaries. We contribute at least the minimum amount required under IRS regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of the fund assets and our pension obligation. We contributed $35 million in 2004, $46 million in 2003, $27 million in 2002, $44 million in 2001 and $24 million in 2000. APS and other subsidiaries fund their share of the pension contribution, of which APS represents approximately 92% of the total funding amounts described above. The assets in the plan are comprised of common stocks, bonds and real estate. Future year contribution amounts are dependent
43
on fund performance and fund valuation assumptions. The minimum required contribution to be made to our pension plan in 2005 is estimated to be approximately $50 million. The expected contribution to our other postretirement benefit plans in 2005 is estimated to be approximately $40 million.
APS
APS’ capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. See “ACC Financing Order” in Note 3 for a discussion of the $500 million financing arrangement between APS and Pinnacle West Energy authorized by the ACC pursuant to the Financing Order.
APS pays for its capital requirements with cash from operations and, to the extent necessary, external financings. APS has historically paid for its dividends to Pinnacle West with cash from operations. See “Pinnacle West (Parent Company)” above for a discussion of the common equity ratio that APS must maintain in order to pay dividends to Pinnacle West.
On February 15, 2004, $125 million of APS’ 5.875% notes due 2004 were redeemed at maturity and on March 1, 2004, $80 million of APS’ First Mortgage Bonds, 6.625% Series due 2004 were redeemed at maturity. APS used cash from operations and short-term debt to redeem the maturing debt.
On March 31, 2004, Navajo County, Arizona Pollution Control Corporation issued $166 million of variable interest rate pollution control bonds, 2004 Series A-E, due 2034. The bonds were issued to refinance $166 million of outstanding pollution control bonds. The refinanced bonds were all $25 million of the Navajo 5.50% bonds due 2028 and $141 million of the Navajo 5.875% bonds due 2028. The Series A-E bonds are payable solely from revenues obtained from APS pursuant to a loan agreement between APS and Navajo County, Arizona Pollution Control Corporation. These bonds are classified as long-term debt on our Consolidated Balance Sheets. See Note 6.
Also on March 31, 2004, Coconino County, Arizona Pollution Control Corporation issued $13 million of variable interest rate pollution control bonds, 2004 Series A, due 2034. The bonds were issued to refinance $13 million of outstanding pollution control bonds. The refinanced bonds were $13 million of the Coconino 5.875% bonds due 2028. The Series A bonds are payable solely from revenues obtained from APS pursuant to a loan agreement between APS and Coconino County, Arizona Pollution Control Corporation. These bonds are classified as long-term debt on our Consolidated Balance Sheets. See Note 6.
In May 2004, APS renewed its $250 million revolving credit facility, while increasing its size to $325 million and extending its term to three years. The revolver provides liquidity support for APS’ $250 million commercial paper program, as well as an additional $75 million for other liquidity needs and miscellaneous letters of credit.
On June 29, 2004, APS issued $300 million of 5.80% senior unsecured notes due June 30, 2014. The proceeds from the sale of the notes were used to redeem $100 million in aggregate principal amount of APS’ 6.25% Notes due January 15, 2005 and a portion of $300 million in aggregate principal amount of APS’ 7.625% Notes due August 1, 2005.
44
On March 1, 2005, Maricopa County, Arizona Pollution Control Corporation issued $164 million of variable interest rate pollution control bonds, 2004 Series A-E, due 2029. The bonds were issued to refinance $164 million of outstanding pollution control bonds. The Series A-E bonds are payable solely from revenues obtained from APS pursuant to a loan agreement between APS and Maricopa County, Arizona Pollution Control Corporation. These bonds are classified as long-term debt on our Consolidated Balance Sheets.
APS has retired all first mortgage bonds issued by APS under its 1946 mortgage and deed of trust, including the first mortgage bonds securing APS senior notes. On April 30, 2004, APS terminated its mortgage and deed of trust and, as a result, is not able to issue any additional first mortgage bonds under that mortgage.
APS’ outstanding debt was approximately $2.7 billion at December 31, 2004. APS had committed lines of credit with various banks of $325 million at December 31, 2004 which were available either to support the issuance of commercial paper or to be used for bank borrowings, including issuances of letters of credit. At December 31, 2004, APS had no outstanding commercial paper or bank borrowings. APS ended 2004 in an invested position.
Although provisions in APS’ articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements.
Pinnacle West Energy
Pinnacle West Energy’s capital requirements consist primarily of capital expenditures. In May 2004, SNWA paid Pinnacle West Energy approximately $91 million for a 25% interest in the 570 MW Silverhawk combined cycle plant. See the capital expenditures table above for actual capital expenditures for 2004 and projected capital expenditures for the next three years. Pinnacle West Energy’s sources of cash will be cash infusions from the parent and cash from operations.
See “ACC Financing Order” in Note 3 for a discussion of the $500 million financing arrangement between APS and Pinnacle West Energy authorized by the ACC pursuant to the Financing Order.
Other Subsidiaries
During the past three years, SunCor funded its cash requirements with cash from operations and its own external financings. SunCor’s capital needs consist primarily of capital expenditures for land development and retail and office building construction. See the capital expenditures table above for actual capital expenditures in 2004 and projected capital expenditures for the next three years. SunCor expects to fund its capital requirements with cash from operations and external financings.
In 2004, SunCor did not issue any long-term debt; and it redeemed, refinanced or repaid $2 million in long-term debt (see Note 6).
SunCor’s total outstanding debt was approximately $87 million as of December 31, 2004. SunCor’s total short-term debt was $71 million at December 31, 2004, including $35 million of
45
short-term borrowings outstanding under a $90 million line of credit. SunCor’s long-term debt, including current maturities, totaled $16 million at December 31, 2004.
We expect SunCor to make cash distributions to the parent company of approximately $80 to $100 million in 2005 based on anticipated asset sales activities.
El Dorado funded its cash requirements during the past three years, primarily for NAC in 2002, with cash infused by the parent company and with cash from operations. As described above, during 2004, El Dorado sold its limited partnership interest in the Phoenix Suns and its ownership interest in NAC. El Dorado expects minimal capital requirements over the next three years and intends to focus on prudently realizing the value of its existing investments.
APS Energy Services’ cash requirements during the past three years were funded with cash infusions from the parent company and with cash from operations.
CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.
Regulatory Accounting
Regulatory accounting allows for the actions of regulators, such as the ACC and the FERC, to be reflected in our financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. We had $135 million of regulatory assets on the Consolidated Balance Sheets at December 31, 2004. A component of the 2004 Settlement Agreement, which is subject to ACC approval, would allow APS to acquire the PWEC Dedicated Assets from Pinnacle West Energy, with a net carrying value of approximately $850 million, and rate base the PWEC Dedicated Assets at a rate base value of $700 million. This would result in a mandatory rate base disallowance of approximately $150 million. As a result, for financial reporting purposes, APS would recognize a one-time, after-tax net plant write-off of approximately $90 million in the period when the plant transfer to APS is completed and would reduce annual depreciation expense by approximately $5 million. See Notes 1 and 3 for more information about regulatory assets, APS’ general rate case and the 2004 Settlement Agreement.
Pensions and Other Postretirement Benefit Accounting
Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit liability and expense can have a significant impact on our earnings and financial position. The most relevant actuarial assumptions are the discount rate used to measure our liability and net periodic cost, the expected long-term rate of return on plan assets used to estimate
46
earnings on invested funds over the long-term, and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the 2004 projected benefit obligation, our 2004 reported pension liability on the Consolidated Balance Sheets and our 2004 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the 2004 accumulated other postretirement benefit obligation and our 2004 reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):
47
See Note 8 for further details about our pension and other postretirement benefit plans.
Derivative Accounting
Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, will determine whether we use accrual accounting (for contracts designated as normal) or fair value (mark-to-market) accounting. Mark-to-market accounting requires that changes in the fair value are recognized periodically in income unless certain hedge criteria are met. For fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item associated with the hedged risk are recognized in earnings. For cash flow hedges, changes in the fair value of the derivative are recognized in common stock equity (as a component of other comprehensive income (loss)).
The fair value of our derivative contracts is not always readily determinable. In some cases, we use models and other valuation techniques to determine fair value. The use of these models and valuation techniques sometimes requires subjective and complex judgement. Actual results could differ from the results estimated through application of these methods. Our marketing and trading portfolio consists of structured activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. See “Market Risks – Commodity Price Risk” below for quantitative analysis. See Note 1 for discussion on accounting policies and Note 18 for a further discussion on derivative and energy trading accounting.
OTHER ACCOUNTING MATTERS
Accounting for Derivative and Trading Activities
We adopted EITF 02-3 in the fourth quarter of 2002. We recorded a $66 million after-tax charge in net income as a cumulative effect adjustment for the previously recorded accumulated unrealized mark-to-market on energy trading contracts that did not meet the accounting definition of a derivative. Our energy trading contracts that are derivatives are accounted for at fair value under SFAS No. 133. Contracts that do not meet the definition of a derivative are now accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received.
See Notes 1 and 18 for further information on accounting for derivatives.
Variable Interest Entities
See “Liquidity and Capital Resources – Off-Balance Sheet Arrangements” and Note 20 for a discussion of VIEs.
PINNACLE WEST CONSOLIDATED – FACTORS AFFECTING OUR FINANCIAL OUTLOOK
We believe APS’ general rate case, including the proposed settlement pending before the ACC is the key issue affecting our outlook. See “APS General Rate Case; 2004 Settlement Agreement” in Note 3 for a detailed discussion of this rate case and proposed settlement.
Factors Affecting Operating Revenues, Purchased Power and Fuel Costs
General Electric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and from competitive retail and wholesale power markets in the western United States. These revenues are affected by electricity sales volumes related to customer mix, customer growth and average usage per customer as well as electricity prices and variations in weather from
48
period to period. Competitive sales of energy and energy-related products and services are made by APS Energy Services in western states that have opened to competition.
Customer and Sales Growth The customer and sales growth referred to in this paragraph applies to Native Load customers and sales to them. Customer growth in APS’ service territory averaged about 3.4% a year for the three years 2002 through 2004; we currently expect customer growth to average about 3.8% per year from 2005 to 2007. We currently estimate that total retail electricity sales in kilowatt-hours will grow 5.0% on average, from 2005 through 2007, before the effects of weather variations. Customer growth for the year ended December 31, 2004 compared with the prior year was 3.7%.
Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth and usage patterns. Our experience indicates that a reasonable range of variation in our kilowatt-hour sales projection attributable to such economic factors can result in increases or decreases in annual net income of up to $10 million.
Retail Rate Changes APS has a rate settlement agreement pending before the ACC that includes, among other things, a proposed general rate increase of 4.21% and a power supply adjuster that would provide timely recovery of variations in purchased power and fuel prices. See “APS General Rate Case; 2004 Settlement Agreement” in Note 3. APS expects to file another general rate case in late 2005.
WeatherIn forecasting retail sales growth, we assume normal weather patterns based on historical data. Historical extreme weather variations have resulted in annual variations in net income in excess of $20 million. However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $10 million.
TradingIn accordance with GAAP, we adopted EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” in the fourth quarter of 2002. As a consequence, we are recording structured trading transactions completed prior to implementation of EITF 02-3 that do not qualify as derivatives for financial accounting purposes on the accrual method, recognizing the revenues and associated purchased power and fuel costs as the respective commodities are delivered. We expect the deliveries under these historical contracts to contribute the following amounts to net income: approximately $12 million each year in 2005 through 2007 and approximately $7 million in 2008.
Purchased Power and Fuel Costs Purchased power and fuel costs are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service and our hedging program for managing such costs. See “Natural Gas Supply” in Note 11 for more information on fuel costs. See “APS General Rate Case; 2004 Settlement Agreement” in Note 3 for information regarding a power supply adjuster.
Wholesale Power Market Conditions The marketing and trading division focuses primarily on managing APS’ purchased power and fuel risks in connection with its costs of serving retail customer demand. We moved this division to APS in early 2003 for future marketing and trading activities (existing wholesale contracts remained at Pinnacle West) as a result of the ACC’s
49
Track A Order prohibiting APS’ transfer of generating assets to Pinnacle West Energy. Additionally, the marketing and trading division, subject to specified parameters, markets, hedges and trades in electricity, fuels and emission allowances and credits. Our future earnings will be affected by the strength or weakness of the wholesale power market. The market has suffered a substantial reduction in overall liquidity because there are fewer creditworthy counterparties and because several key participants have exited the market or scaled back their activities.
Other Factors Affecting Financial Results
Operations and Maintenance Expenses Operations and maintenance expenses are impacted by growth, power plant additions and operations, inflation, outages, higher trending pension and other postretirement benefit costs and other factors.
Depreciation and Amortization Expenses Depreciation and amortization expenses are impacted by net additions to utility plant and other property, which includes generation construction or acquisition, and changes in regulatory asset amortization. Silverhawk was placed in service in May 2004. APS plans to acquire the Sundance Plant in 2005 and, in accordance with the proposed rate settlement, to issue requests for proposals to acquire additional long-term resources in 2006 and 2007. As part of the 1999 Settlement Agreement, APS amortized certain regulatory assets over a period that ended June 30, 2004. Amortization in the last three years is as follows (dollars in millions):
Property Taxes Taxes other than income taxes consist primarily of property taxes, which are affected by tax rates and the value of property in-service and under construction. The average property tax rate for APS, which currently owns the majority of our property, was 9.2% of assessed value for 2004 and 9.3% for 2003. We expect property taxes to increase primarily due to our generation construction program, as the plants phase-in to the property tax base, the planned acquisition of the Sundance Plant and our additions to existing facilities.
Interest Expense Interest expense is affected by the amount of debt outstanding and the interest rates on that debt. The primary factors affecting borrowing levels in the next several years are expected to be our capital requirements and our internally generated cash flow. Capitalized interest offsets a portion of interest expense while capital projects are under construction. We stop accruing capitalized interest on a project when it is placed in commercial operation. As noted above, we placed new power plants in commercial operation in 2001, 2002, 2003 and 2004. Interest expense is also affected by interest rates on variable-rate debt and interest rates on the refinancing of the Company’s future liquidity needs. In addition, see Note 1 for a discussion of AFUDC.
Retail Competition The regulatory developments and legal challenges to the Rules discussed in Note 3 have raised considerable uncertainty about the status and pace of retail electric competition and of electric restructuring in Arizona. Although some very limited retail competition existed in APS’ service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.
50
Subsidiaries In the case of SunCor, efforts to accelerate asset sales activities in 2004 were successful. A portion of these sales have been, and additional amounts may be required to be, reported as discontinued operations on our Consolidated Statements of Income. SunCor’s net income was $45 million in 2004. See Note 22 for further discussion. We anticipate SunCor’s earnings contributions in 2005 to be approximately $50 million after income taxes.
El Dorado’s historical results are not indicative of future performance. El Dorado’s income before taxes in 2004 was $40 million. Income taxes were recorded at the parent company. The year ended 2004 includes a $35 million gain ($21 million after tax) related to the sale of El Dorado’s limited partnership interest in the Phoenix Suns. El Dorado sold its investment in NAC on November 18, 2004, which resulted in a pretax gain of $4 million and is classified as discontinued operations in 2004 and prior years. See Note 22 for information regarding the sale of NAC.
General Our financial results may be affected by a number of broad factors. See “Forward-Looking Statements” for further information on such factors, which may cause our actual future results to differ from those we currently seek or anticipate.
Market Risks
Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by our nuclear decommissioning trust fund.
Interest Rate and Equity Risk
Our major financial market risk exposure is to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and interest earned by our nuclear decommissioning trust fund (see Note 12). Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. On January 29, 2004, we entered into two fixed-for-floating interest rate swap transactions on our $300 million 6.4% senior note. These transactions qualify as fair value hedges under SFAS No 133. See Note 6.
The tables below present contractual balances of our consolidated long-term and short-term debt at the expected maturity dates as well as the fair value of those instruments on December 31, 2004 and 2003. The interest rates presented in the tables below represent the weighted-average interest rates for the years ended December 31, 2004 and 2003 (dollars in thousands):
51
The tables below present contractual balances of APS’ long-term debt at the expected maturity dates as well as the fair value of those instruments on December 31, 2004 and 2003. The interest rates presented in the tables below represent the weighted-average interest rates for the years ended December 31, 2004 and 2003 (dollars in thousands):
52
Commodity Price Risk
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. Our ERMC, consisting of officers and key management personnel, oversees company-wide energy risk management activities and monitors the results of marketing and trading activities to ensure compliance with our stated energy risk management and trading policies. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity, fuels and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.
The mark-to-market value of derivative instruments related to our risk management and trading activities are presented in two categories consistent with our business segments:
The following tables show the pretax changes in mark-to-market of our non-trading and trading derivative positions in 2004 and 2003 (dollars in millions):
53
The tables below show the fair value of maturities of our non-trading and trading derivative contracts (dollars in millions) at December 31, 2004 by maturities and by the type of valuation that is performed to calculate the fair values. See Note 1, “Derivative Accounting,” for more discussion of our valuation methods.
Regulated Electricity
Marketing and Trading
The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management and trading assets and liabilities included on Pinnacle West’s Consolidated Balance Sheets at December 31, 2004 and 2003 (dollars in millions).
54
Credit Risk
We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including two counterparties for which a worst case exposure represents approximately 35% of Pinnacle West’s $391 million of risk management and trading assets as of December 31, 2004. See Note 1, “Derivative Accounting” for a discussion of our credit valuation adjustment policy. See Note 18 for further discussion of credit risk.
ARIZONA PUBLIC SERVICE COMPANY – RESULTS OF OPERATIONS
Throughout the following explanations of APS’ results of operations, we refer to “gross margin.” Gross margin refers to electric operating revenues less purchased power and fuel costs. “Gross margin” is a “non-GAAP financial measure,” as defined in accordance with SEC rules. Operating income (a GAAP financial measure) plus specified operating expenses (operations and maintenance, depreciation and amortization, operating income taxes and other taxes), as disclosed on the Statements of Income, is equal to gross margin. We view gross margin as an important performance measure of the core profitability of our operations. This measure is a key component of our internal financial reporting and is used by our management in analyzing our business segments. We believe that investors benefit from having access to the same financial measures that our management uses. In addition, we have reclassified certain prior period amounts to conform to our current period presentation.
APS’ net income for the year ended December 31, 2004 was $200 million compared with $181 million for the prior year. The $19 million increase in the period-to-period comparison reflects lower regulatory asset amortization; the benefit of customer growth; decreased purchased power and fuel costs primarily due to lower prices for capacity purchases; increased interest income and lower replacement power costs due to fewer unplanned outages. These positive factors were partially offset by increased operations and maintenance costs related to increased generation, customer service and personnel costs; the effects of weather on retail sales; higher depreciation and amortization related to increased delivery and other assets; lower realized margins on energy trading due to higher wholesale electricity prices; a retail electricity price reduction; lower income tax credits; and higher interest expense primarily due to increased utility plant in service.
55
Additional details on the major factors that increased (decreased) net income for the year ended December 31, 2004 compared with the prior year are contained in the following table (dollars in millions).
Regulated Electricity Revenues
Regulated electricity revenues were $52 million higher in the year ended December 31, 2004 compared with the prior year, primarily as a result of:
Marketing and Trading Revenues
Marketing and trading revenues were $40 million higher in the year ended December 31, 2004 compared with the prior year, primarily as a result of:
56
APS’ net income for the year ended December 31, 2003 was $181 million compared with $199 million for the prior year. The $18 million decrease in the period-to-period comparison reflects higher purchased power and fuel costs resulting from higher prices for hedged gas and purchased power; higher replacement power costs from plant outages due to higher market prices and more unplanned outages (Cholla Unit 3 experienced an unplanned outage from August of 2003 through November of 2003); higher operations and maintenance costs related to increased pension and other benefits; two retail electricity price reductions; and higher depreciation expense related to increased delivery and other assets. These negative factors were partially offset by higher retail sales primarily due to customer growth and favorable weather; lower operating costs primarily related to severance costs recorded in 2002; lower regulatory asset amortization; tax credits and favorable income tax adjustments related to prior years resolved in 2003; higher income related to APS’ return to the AFUDC method of capitalizing construction finance costs; and increased generation sales other than Native Load primarily due to higher sales volumes, partially offset by lower unit margins.
57
Additional details on the major factors that increased (decreased) net income for the year ended December 31, 2003 compared with the prior year are contained in the following table (dollars in millions).
Regulated electricity revenues were $97 million higher in the year ended December 31, 2003 compared with the prior year, primarily as a result of:
58
Marketing and trading revenues were $71 million higher in the year ended December 31, 2003 compared with the prior year, primarily as a result of:
LIQUIDITY AND CAPITAL RESOURCES – ARIZONA PUBLIC SERVICE COMPANY
The following table summarizes contractual requirements for APS as of December 31, 2004 (dollars in millions):
59
RISK FACTORS
Exhibit 99.31 and Exhibit 99.32, which are hereby incorporated by reference, contain a discussion of risk factors affecting Pinnacle West and APS, respectively.
FORWARD-LOOKING STATEMENTS
60
61
ITEM 7A. QUANTITATIVE AND QUALITATIVEDISCLOSURES ABOUT MARKET RISK
See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” in Item 7 above for a discussion of quantitative and qualitative disclosures about market risk.
62
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS ANDFINANCIAL STATEMENT SCHEDULE
See Note 13 for the selected quarterly financial data required to be presented in this Item.
63
MANAGEMENT’S REPORT ON INTERNAL CONTROLOVER FINANCIAL REPORTING(PINNACLE WEST CAPITAL CORPORATION)
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13(a)-15(f). Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control – Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2004. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and relates also to the Company’s consolidated financial statements.
March 15, 2005
64
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders ofPinnacle West Capital CorporationPhoenix, Arizona
We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule, an opinion on management’s assessment, and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audit of financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
65
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
As discussed in Note 18 to the consolidated financial statements, in 2002 the Company changed its method for accounting for trading activities in order to comply with the provisions of Emerging Issues Task Force Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.
DELOITTE & TOUCHE LLPPhoenix, Arizona
66
PINNACLE WEST CAPITAL CORPORATIONCONSOLIDATED STATEMENTS OF INCOME(dollars and shares in thousands, except per share amounts)
See Notes to Pinnacle West’s Consolidated Financial Statements.
67
PINNACLE WEST CAPITAL CORPORATIONCONSOLIDATED BALANCE SHEETS(dollars in thousands)
68
69
PINNACLE WEST CAPITAL CORPORATIONCONSOLIDATED STATEMENTS OF CASH FLOWS(dollars in thousands)
70
PINNACLE WEST CAPITAL CORPORATIONCONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY(dollars in thousands)
71
PINNACLE WEST CAPITAL CORPORATIONNOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Consolidation and Nature of Operations
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor and El Dorado (principally NAC). See Note 22 for a discussion of the sale of NAC in November 2004. Significant intercompany accounts and transactions between the consolidated companies have been eliminated.
APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave county in northwestern Arizona. Through its marketing and trading division, APS also generates, sells and delivers electricity to wholesale customers in the western United States. Pinnacle West Energy, which was formed in 1999, is the subsidiary through which we conduct our unregulated generation operations. APS Energy Services was formed in 1998 and provides competitive commodity energy and energy-related products to key customers in competitive markets in the western United States. SunCor is a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico, Idaho and Utah. El Dorado is an investment firm.
Accounting Records and Use of Estimates
Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. We have reclassified certain prior year amounts to conform to the current year presentation.
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances and in interest rates. We manage risks associated with these market fluctuations by utilizing various instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.
We account for our derivative contracts in accordance with SFAS No. 133, as amended by SFAS No. 149, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133 requires that entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. Changes in the fair value of derivative instruments are either recognized periodically in income or, if certain hedge criteria are met, in common stock equity (as a component of other comprehensive income (loss)). SFAS No. 133 provides a scope exception for contracts that meet the normal purchases and sales criteria specified in the standard.
72
Prior to the fourth quarter of 2002, we accounted for our trading activity at fair value, with changes in fair value reported in earnings as required by EITF 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” In the fourth quarter of 2002, we adopted EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” which rescinded EITF 98-10. We recorded a $66 million after-tax charge in net income as a cumulative effect adjustment for the previously recorded accumulated unrealized mark-to-market on energy trading contracts that did not meet the accounting definition of a derivative. Our energy trading contracts that are derivatives are accounted for at fair value under SFAS No. 133, as amended. Energy trading contracts that do not meet the definition of a derivative are now accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received.
Under fair value (mark-to-market) accounting, derivative contracts for the purchase or sale of energy commodities are reflected at fair market value, net of valuation adjustments, with resulting unrealized gains and losses recorded as current or long-term assets and liabilities from risk management and trading activities on the Consolidated Balance Sheets.
We determine fair market value using actively-quoted prices when available. We consider quotes for exchange-traded contracts and over-the-counter quotes obtained from independent brokers to be actively-quoted.
When actively-quoted prices are not available, we use prices provided by other external sources. This includes quarterly and calendar year quotes from independent brokers, which we convert into monthly prices using historical relationships.
For options, long-term contracts and other contracts for which price quotes are not available, we use models and other valuation methods. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. The primary valuation technique we use to calculate the fair value of contracts where price quotes are not available is based on the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at the more illiquid delivery points. We also value option contracts using a variation of the Black-Scholes option-pricing model.
For non-exchange traded contracts, we calculate fair market value based on the average of the bid and offer price, and we discount to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks based on the financial condition of counterparties. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed-out or hedged.
The credit valuation adjustment represents estimated credit losses on our overall exposure to counterparties, taking into account netting arrangements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. Counterparties in the portfolio consist principally of major energy companies, municipalities, local distribution companies and financial institutions. We maintain credit policies that management believes minimize overall credit risk. Determination of the credit quality of counterparties is based upon a number of factors, including credit ratings, financial condition, project economics and collateral requirements. When
73
applicable, we employ standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.
The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our marketing and trading portfolio includes structured activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. Our practice is to hedge within timeframes established by the ERMC.
See Note 18 for additional information about our derivative and energy trading accounting policies.
APS is regulated by the ACC and the FERC. The accompanying financial statements reflect the rate-making policies of these commissions. For regulated operations, we prepare our financial statements in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of regulatory decisions in its financial statements. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent expected future costs that have already been collected from customers.
Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in the state and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.
As part of the 1999 Settlement Agreement, APS amortized certain regulatory assets over a period that ended June 30, 2004. Amortization in the last three years is as follows (dollars in millions):
The detail of regulatory assets is as follows (dollars in millions):
74
The detail of regulatory liabilities is as follows (dollars in millions):
Utility Plant and Depreciation
Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities. We report utility plant at its original cost, which includes:
We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Prior to 2003, we charged removal costs, less salvage, to accumulated depreciation. Effective January 1, 2003, we applied the provisions of SFAS No. 143. The standard requires that liabilities associated with the retirement of tangible long-lived assets be recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating
75
expense and the capitalized cost is depreciated over the useful life of the long-lived asset. See Note 12.
APS records a regulatory liability for the asset retirement obligations related to its regulated assets. This regulatory liability represents the difference between the amount that has been recovered in regulated rates and the amount calculated under SFAS No. 143. APS believes it can recover in regulated rates the transition and ongoing current period costs calculated in accordance with SFAS No. 143.
We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2004 were as follows:
For the years 2002 through 2004, the depreciation rates, as prescribed by our regulators, ranged from a low of 1.51% to a high of 12.5%. The weighted-average rate was 3.36% for 2004, 3.35% for 2003 and 3.35% for 2002. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 55 years.
Investments
El Dorado accounts for its investments using the equity (if significant influence) and cost (less than 20% ownership) methods. See Note 22 for a discussion of the sale of NAC.
The Company’s investments have been reviewed in accordance with EITF 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments,” and no other-than-temporary impairments were identified.
Capitalized Interest
Capitalized interest represents the cost of debt funds used to finance non-regulated construction projects. Plant construction costs, including capitalized interest, are expensed through depreciation when completed projects are placed into commercial operation. The rate used to calculate capitalized interest was a composite rate of 4.44% for 2004, 4.55% for 2003 and 4.80% for 2002. Capitalized interest ceases to accrue when construction is complete.
Allowance for Funds Used During Construction
AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction of regulated utility plant. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.
76
AFUDC was calculated by using a composite rate of 8.42% for 2004 and 8.55% for 2003. APS compounds AFUDC monthly and ceases to accrue AFUDC when construction work is completed and the property is placed in service.
In 2003, APS returned to the AFUDC method of capitalizing interest and equity costs associated with construction projects in a regulated utility. This is consistent with APS returning to a vertically-integrated utility, as evidenced by APS’ 2003 general rate case filing, which includes the request for rate recognition of generation assets. Prior to 2003, APS capitalized interest in accordance with SFAS No. 34, “Capitalization of Interest Cost.” Although AFUDC both increases the plant balance and results in higher current earnings during the construction period, AFUDC is realized in future revenues through depreciation provisions included in rates. This change increased earnings by $11 million in 2003 as compared to what it would have been under SFAS No. 34.
Electric Revenues
We derive electric revenues from sales of electricity to our regulated Native Load customers and sales to other parties from our marketing and trading activities. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. However, the determination and billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers since the date of the last meter reading and billing and the corresponding unbilled revenue are estimated. We exclude sales taxes on electric revenues from both revenue and taxes other than income taxes.
Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and purchased power and fuel costs.
All gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Consolidated Statements of Income on a net basis.
Real Estate Revenues
SunCor recognizes revenue from land, home and qualifying commercial operating assets sales in full, provided (a) the income is determinable, that is, the collectibility of the sales price is reasonably assured or the amount that will not be collectible can be estimated, and (b) the earnings process is virtually complete, that is, SunCor is not obligated to perform significant activities after the sale to earn the income. Unless both conditions exist, recognition of all or part of the income is postponed under the percentage of completion method per SFAS No. 66, “Accounting for Sales of Real Estate.” SunCor recognizes income only after the assets’ title has passed. A single method of recognizing income is applied to all sales transactions within an entire home, land or commercial development project. Commercial property and management revenues are recorded over the term of the lease or period in which services are provided. In addition, see Note 22 – Discontinued Operations.
77
Real Estate Investments
Real estate investments primarily include SunCor’s land, home inventory and investments in joint ventures. Land includes acquisition costs, infrastructure costs, property taxes and capitalized interest directly associated with the acquisition and development of each project. Land under development and land held for future development are stated at accumulated cost, except that, to the extent that such land is believed to be impaired, it is written down to fair value. Land held for sale is stated at the lower of accumulated cost or estimated fair value less costs to sell. Home inventory consists of construction costs, improved lot costs, capitalized interest and property taxes on homes under construction. Home inventory is stated at the lower of accumulated cost or estimated fair value less costs to sell. Investments in joint ventures for which SunCor does not have a controlling financial interest are not consolidated but are accounted for using the equity method of accounting. In 2003, SunCor acquired two joint ventures for $10 million and consolidated $53 million of assets and $43 million of liabilities, which are included on the Consolidated Balance Sheets at December 31, 2003. The $10 million cash investment is included on the other investing line of the Consolidated Statements of Cash Flow at December 31, 2003. In addition, see Note 22 – Discontinued Operations.
Cash and Cash Equivalents
We consider all highly liquid investments purchased with an initial maturity of three months or less to be cash equivalents.
We have investments in auction rate securities in which interest rates are reset on a short-term basis; however, the underlying contract maturity dates extend beyond three months. We classify the investments in auction rate securities as investments in debt securities on our Consolidated Balance Sheets. We have reclassified cash at December 31, 2003 of $92 million to investment in debt securities. Included in that reclassification is $70 million related to APS. The purchase and sale activities related to these investments have also been reclassified on the Consolidated Statement of Cash Flows.
Nuclear Fuel
APS charges nuclear fuel to fuel expense by using the unit-of-production method. The unit-of-production method is an amortization method based on actual physical usage. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense.
APS also charges nuclear fuel expense for the permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel, and it charges APS $0.001 per kWh of nuclear generation. See Note 11 for information about spent nuclear fuel disposal and Note 12 for information on nuclear decommissioning costs.
Income Taxes
Income taxes are provided using the asset and liability approach prescribed by SFAS No. 109, “Accounting for Income Taxes.” We file our federal income tax return on a consolidated basis and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each subsidiary
78
as though each subsidiary filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company. See Note 4.
Reacquired Debt Costs
For reacquired debt costs related to the regulated portion of APS’ business, APS defers those gains and losses incurred upon early retirement and is seeking recovery of the net amount of losses in the APS general rate case (see Note 3).
Stock-Based Compensation
In 2002, we began applying the fair value method of accounting for stock-based compensation, as provided for in SFAS No. 123, “Accounting for Stock-Based Compensation.” The fair value method of accounting is the preferred method. In accordance with the transition requirements of SFAS No. 123, we applied the fair value method prospectively, beginning with 2002 stock grants. In prior years, we recognized stock compensation expense based on the intrinsic value method allowed in Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.”
The following chart compares our net income, stock compensation expense and earnings per share to what those items would have been if we had recorded stock compensation expense based on the fair value method for all stock grants through 2004 (dollars in thousands, except per share amounts):
In order to calculate the fair value of the 2004, 2003 and 2002 stock option grants and the pro forma information above, we calculated the fair value of each fixed stock option in the incentive plans using the Black-Scholes option-pricing model. The fair value was calculated based on the date
79
the option was granted. The following weighted-average assumptions were also used in order to calculate the fair value of the stock options:
See Note 16 for further discussion about our stock compensation plans.
Intangible Assets
We have no goodwill recorded and have separately disclosed other intangible assets on Pinnacle West’s Consolidated Balance Sheets in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets.” The intangible assets are amortized over their finite useful lives. Amortization expense was $34 million in 2004, $25 million in 2003, and $21 million in 2002. Estimated amortization expense on existing intangible assets over the next five years is $33 million in 2005, $31 million in 2006, $25 million in 2007, $16 million in 2008, and $1 million in 2009. At December 31, 2004, the weighted average amortization period for intangible assets is 7 years.
2. New Accounting Standards
In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” The standard establishes accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. SFAS No. 123R is effective as of the beginning of the first interim or annual period that begins after June 15, 2005. We are currently accounting for stock-based compensation using the fair value method and are evaluating the impacts of this new guidance, but we do not believe it will have a material impact on our financial statements.
See the following Notes for information about new accounting standards and other accounting matters:
80
3. Regulatory Matters
Electric Industry Restructuring
State
APS General Rate Case; 2004 Settlement Agreement
On June 27, 2003, APS filed a general rate case with the ACC and requested a $175.1 million, or 9.8%, increase in its annual retail electricity revenues, intended to become effective July 1, 2004. In this rate case, APS updated its cost of service and rate design.
The general rate case also addresses the implementation of rate adjustment mechanisms that were the subject of ACC hearings in April 2003. The rate adjustment mechanisms, which were authorized as a result of the 1999 Settlement Agreement, would allow APS to recover several types of costs, the most significant of which are power supply costs (fuel and purchased power costs) and costs associated with complying with the Rules.
On August 18, 2004, a substantial majority of the parties to the rate case, including APS, the ACC staff, the Arizona Residential Utility Consumer Office, other customer groups, and merchant power plant intervenors entered into an agreement that proposes terms under which the rate case would be settled (the “2004 Settlement Agreement”).
Key financial components of the 2004 Settlement Agreement, which is subject to ACC approval, are as follows:
81
acquired and rate-based the PWEC Dedicated Assets at the value described above.
On February 28, 2005, the administrative law judge in the general rate case issued a recommended order. The recommended order proposes ACC approval of the 2004 Settlement Agreement with two changes related to the PSA. First, the amount of gas costs that APS could recover under the annual PSA would be limited to $500 million per year. Second, although the 2004 Settlement Agreement provides that the PSA would remain in effect for a minimum five-year period, under the recommended order the ACC would be able to eliminate the PSA at any time, if appropriate, if APS files a rate case before the expiration of the five-year period or APS does not comply with the terms of the PSA. If APS exceeds the gas costs that could be recoverable under the PSA or if the ACC eliminates the PSA, APS would retain the right to file a rate case to reset its base rates.
On March 14, 2005, the parties to the 2004 Settlement Agreement jointly filed suggested changes to the recommended order addressing, among other things, the recommended order’s proposed treatment of the PSA. The ACC has scheduled open meetings on March 25 and March 28, 2005 to consider the recommended order and suggested changes. APS cannot predict the outcome of this matter.
82
ACC Financing Order
On May 12, 2003, APS issued $500 million of debt pursuant to the Financing Order and made a $500 million loan to Pinnacle West Energy. Pinnacle West Energy distributed the net proceeds of that loan to us to fund the repayment of a portion of the debt we incurred to finance the construction of the PWEC Dedicated Assets.
The ACC granted the Financing Order subject to various conditions. One of these conditions is that APS must maintain a common equity ratio of at least forty percent and may not pay common dividends if such payment would reduce its common equity ratio below that threshold, unless otherwise waived by the ACC.
In addition, the Financing Order required the ACC staff to conduct an inquiry into our and our affiliates’ compliance with the retail electric competition and related rules and decisions. On June 13, 2003, APS submitted its report on these matters to the ACC staff. As part of the 2004 Settlement Agreement, this inquiry would be concluded with no further action by the ACC.
Retail Electric Competition Rules
The Rules approved by the ACC include the following major provisions:
83
unaffiliated party or parties or to a separate corporate affiliate or affiliates. Under the 1999 Settlement Agreement, APS received a waiver to allow transfer of its competitive electric assets and services to affiliates no later than December 31, 2002. However, as discussed below, in 2002 the ACC reversed its decision, as reflected in the Rules, to require APS to transfer its generation assets.
Under the 1999 Settlement Agreement, the Rules are to be interpreted and applied, to the greatest extent possible, in a manner consistent with the 1999 Settlement Agreement. If the two cannot be reconciled, APS must seek, and the other parties to the 1999 Settlement Agreement must support, a waiver of the Rules in favor of the 1999 Settlement Agreement.
On November 27, 2000, a Maricopa County, Arizona, Superior Court judge issued a final judgment holding that the Rules are unconstitutional and unlawful in their entirety due to failure to establish a fair value rate base for competitive electric service providers and because certain of the Rules were not submitted to the Arizona Attorney General for certification. The judgment also invalidates all ACC orders authorizing competitive electric service providers, including APS Energy Services, to operate in Arizona. We do not believe the ruling affected the 1999 Settlement Agreement. The 1999 Settlement Agreement was not at issue in the consolidated cases before the judge. Further, the ACC made findings related to the fair value of APS’ property in the order approving the 1999 Settlement Agreement. The ACC and other parties aligned with the ACC appealed the ruling to the Arizona Court of Appeals, and in January 2004, the Court invalidated some, but not all, of the Rules as either violative of Arizona’s constitutional requirement that the ACC consider the “fair value” of a utility’s property in setting rates or as being beyond the ACC’s constitutional and statutory powers. Other Rules were set aside for failure to submit such regulations to the Arizona Attorney General for approval as required by statute. A request for the Arizona Supreme Court to review the Court of Appeals decision was denied on January 4, 2005.
Track A Order
On September 10, 2002, the ACC issued the Track A Order, in which the ACC, among other things:
On November 15, 2002, APS filed appeals of the Track A Order in the Maricopa County, Arizona Superior Court and in the Arizona Court of Appeals. Arizona Public Service Company vs. Arizona Corporation Commission, CV 2002-0222 32. Arizona Public Service Company vs. Arizona Corporation Commission, 1CA CC 02-0002. On December 13, 2002, APS and the ACC staff agreed to principles for resolving certain issues raised by APS in its appeals of the Track A Order. The major provisions of the principles include, among other things, the following:
84
On August 27, 2003, APS, Pinnacle West and Pinnacle West Energy filed a lawsuit asserting damage claims relating to the Track A Order. Arizona Public Service Company et al. v. The State of Arizona ex rel., Superior Court of the State of Arizona, County of Maricopa, No. CV2003-016372.
Upon the ACC’s issuance of a final, non-appealable order approving the 2004 Settlement Agreement, APS, Pinnacle West, and Pinnacle West Energy will dismiss the litigation described under this “Track A” heading.
Track B Order
On March 14, 2003, the ACC issued the Track B Order, which required APS to solicit bids for certain estimated amounts of capacity and energy for periods beginning July 1, 2003. For 2003, APS was required to solicit competitive bids for about 2,500 MW of capacity and about 4,600 gigawatt-hours of energy, or approximately 20% of APS’ total retail energy requirements.
APS issued requests for proposals in March 2003 and, by May 6, 2003, APS entered into contracts to meet all or a portion of its requirements for the years 2003 through 2006 as follows:
Effective upon final ACC approval of the 2004 Settlement Agreement and the closing of the purchase of the Sundance Plant discussed below, the Track B contracts with Pinnacle West Energy and PPL Energy Plus, LLC will be cancelled.
85
Request for Proposals and Asset Purchase Agreement
In early December 2003, APS issued a request for proposals (“2003 RFP”) for long-term power supply resources. On June 1, 2004, APS and PPL Sundance, a wholly-owned subsidiary of PPL Corporation, entered into an asset purchase agreement by which APS agreed to purchase the Sundance Plant. The Sundance Plant, which began commercial operation in July 2002, would provide peaking generation support for APS’ system and reduce APS’ growing needs for new generation resources. The purchase price for the Sundance Plant is approximately $190 million.
On June 1, 2004, APS and PPL Sundance filed a joint application with the ACC with respect to APS’ proposed acquisition of the Sundance Plant. On January 20, 2005, the ACC issued an order confirming APS’ authority to “self-build or buy new generation assets for native load” and stated that APS’ acquisition of the Sundance Plant would be a proper purpose under APS’ existing ACC financing authorizations. APS’ filings with the ACC also had requested that the ACC allow APS to defer for future recovery certain capital and operating costs (net of fuel and purchased power savings) associated with the Sundance Plant acquisition until rate treatment for the Sundance Plant could be considered in APS’ next general rate case. APS’ filings estimated that the deferrals would be approximately $10 million to $15 million before income taxes on an annualized basis. The order issued by the ACC allows APS to record the deferrals for up to 36 months, subject to a number of conditions. However, if APS has a general rate case pending at the end of the 36-month period, the deferral period could extend until the rate case had been decided. The conditions imposed by the order are expected to substantially limit the amount of deferrals that APS will be able to record.
APS’ acquisition of the Sundance Plant is subject to FERC approval and to customary closing conditions. The transaction is targeted to close in the spring of 2005.
APS does not expect to enter into any additional transactions as a result of the 2003 RFP.
Provider of Last Resort Obligation
Although the Rules allow retail customers to have access to competitive providers of energy and energy services, APS is, under the Rules, the “provider of last resort” for standard-offer, full-service customers under rates that have been approved by the ACC. In the event of shortfalls due to unforeseen increases in load demand or generation or transmission outages, APS may need to purchase additional supplemental power in the wholesale spot market. At various times, prices in the spot wholesale market have significantly exceeded the amount included in APS’ current retail rates. There can be no assurance that APS would be able to fully recover the costs of this power. The proposed settlement of APS’ general rate case, discussed above, would, among other things, allow APS to recover purchased power costs.
1999 Settlement Agreement
The following are the major provisions of a settlement agreement entered into in 1999, as approved by the ACC:
86
approximately $24 million ($14 million after taxes), effective July 1, 1999; approximately $28 million ($17 million after taxes), effective July 1, 2000; approximately $27 million ($16 million after taxes), effective July 1, 2001; approximately $28 million ($17 million after taxes), effective July 1, 2002; and approximately $29 million ($18 million after taxes), effective July 1, 2003. For customers having loads of three MW or greater, standard-offer rates have been reduced in varying annual increments that total 5% in the years 1999 through 2002.
87
The regulatory developments and legal challenges to the Rules discussed in this Note have raised considerable uncertainty about the status and pace of retail electric competition and of electric restructuring in Arizona. Although some very limited retail competition existed in APS’ service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory. As competition in the electric industry continues to evolve, we will continue to evaluate strategies and alternatives that will position us to compete in the new regulatory environment.
Federal
In July 2002, the FERC adopted a price mitigation plan that constrains the price of electricity in the wholesale spot electricity market in the western United States. The FERC adopted a price cap of $250 per MWh for the period subsequent to October 31, 2002. Sales at prices above the cap must be justified and are subject to potential refund.
On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking for Standard Market Design for wholesale electric markets. Voluminous comments and reply comments were filed on virtually every aspect of the proposed rule. On April 28, 2003, the FERC Staff issued an additional white paper on the proposed Standard Market Design. The white paper discusses several policy changes to the proposed Standard Market Design, including a greater emphasis on flexibility for regional needs. We cannot currently predict what, if any, impact there may be to the Company if the FERC adopts the proposed rule or any modifications proposed in the comments.
The FERC has been, though its Office of Marker Oversight and Investigations (OMOI), in the process of auditing a number of electric utilities regarding compliance with its regulations. Such an audit of APS and its affiliates was recently completed, and the FERC has issued an order approving the OMOI audit report and directing certain compliance actions. Arizona Public Service Company, 109 FERC ¶ 61,271 (2004).
Chief among the FERC’s findings, APS must pay $4 million for its use of unauthorized point-to-point transmission service. Of the $4 million, APS must distribute: (1) $2.75 million to upgrade the West Phoenix-Lincoln Street 230kV transmission line with high capacity composite
88
conductors; and (2) $1.25 million as a contribution to established low income energy assistance programs in Arizona. APS must not recover these monies from any existing or future wholesale or retail rate recovery mechanism, nor may it announce the low income payment as a public interest contribution. APS must also take certain corrective actions and make quarterly filings detailing its progress in implementing these actions until all are completed.
APS believes that the resolution of these matters will not have a material adverse effect on its financial position, results of operations or liquidity.
4. Income Taxes
Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using the current income tax rates.
APS has recorded a regulatory asset and a regulatory liability related to income taxes on its Balance Sheets in accordance with SFAS No. 71. The regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. The regulatory liability relates to excess deferred taxes resulting primarily from the reduction in federal income tax rates as part of the Tax Reform Act of 1986. APS amortizes this amount as the differences reverse.
As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on the 2001 federal consolidated income tax return. The accelerated deduction resulted in a $200 million reduction in the current income tax liability and a corresponding increase in the plant-related deferred tax liability. In 2002, we received an income tax refund of approximately $115 million related to our 2001 federal consolidated income tax return. The 2001 federal consolidated income tax return is currently under examination by the IRS. As part of this ongoing examination, the IRS is reviewing this accounting method change and the resultant deduction. During 2004, the current income tax liability was increased, with a corresponding decrease to plant-related deferred tax liability, to reflect the expected outcome of this audit. We do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position, results of operations or liquidity.
The income tax liability accounts reflect the tax and interest associated with the most probable resolution of all known and measurable tax exposures.
In 2004 and 2003, we resolved certain prior-year issues with the taxing authorities and recorded tax benefits associated with tax credits and other reductions to income tax expense.
89
The components of income tax expense are as follows (dollars in thousands):
The following chart compares pretax income from continuing operations at the 35% federal income tax rate to income tax expense (dollars in thousands):
The following table sets forth the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):
90
The components of the net deferred income tax liability were as follows (dollars in thousands):
5. Lines of Credit and Short-Term Borrowings
APS had committed lines of credit with various banks of $325 million at December 31, 2004 and $250 million at December 31, 2003, which were available either to support the issuance of up to $250 million in commercial paper or to be used for bank borrowings, including issuance of letters of credit. The current line matures in May 2007. The commitment fees at December 31, 2004 and 2003 for these lines of credit were 0.15% and 0.175% per annum. APS had no bank borrowings outstanding under these lines of credit at December 31, 2004 and 2003. APS had approximately $4.8 million letters of credit issued under the line at December 31, 2004.
APS had no commercial paper borrowings outstanding at December 31, 2004 and 2003. By Arizona statute, APS’ short-term borrowings cannot exceed 7% of its total capitalization unless approved by the ACC.
Pinnacle West had committed lines of credit of $300 million at December 31, 2004 and $275 million at December 31, 2003, which were available either to support the issuance of up to $250
91
million in commercial paper or to be used for bank borrowings, including issuance of letters of credit. The current lines mature in October 2007. Pinnacle West had no outstanding borrowings at December 31, 2004 and December 31, 2003. Pinnacle West had approximately $13 million of letters of credit issued under the line at December 31, 2004 and approximately $15 million of letters of credit issued under the line at December 31, 2003. The commitment fees were 0.175% in 2004 and ranged from 0.125% to 0.175% in 2003. Pinnacle West had no commercial paper borrowings outstanding at December 31, 2004 and 2003. All APS and Pinnacle West bank lines of credit and commercial paper agreements are unsecured.
SunCor had revolving lines of credit totaling $90 million at December 31, 2004 and $120 million at December 31, 2003. The commitment fees were 0.125% in 2004 and 2003. SunCor had $35 million outstanding at December 31, 2004 and $50 million outstanding at December 31, 2003. The weighted-average interest rate was 4.50% at December 31, 2004 and 2003. Interest for 2004 and 2003 was based on LIBOR plus 2% or prime plus 0.5%. The balance is included in short-term debt on the Consolidated Balance Sheets. SunCor had other short-term loans in the amount of $36 million at December 31, 2004 and December 31, 2003. These loans are made up of multiple notes primarily with variable interest rates based on LIBOR plus 2.5% at December 31, 2004 and 2003.
6. Long-Term Debt
APS has retired all first mortgage bonds issued under its 1946 mortgage and deed of trust, including the first mortgage bonds securing APS senior notes. On April 30, 2004, APS terminated its mortgage and deed of trust and, as a result, is not able to issue any additional first mortgage bonds under that mortgage. SunCor’s short and long-term debt is collateralized by interests in certain real property and Pinnacle West’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2004 and 2003 (dollars in thousands):
92
93
Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include a debt-to-total-capitalization ratio and an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet those and other significant covenant requirements. These covenants require that the ratio of debt to total capitalization cannot exceed 65% for the Company and for APS. At December 31, 2004, the ratio was approximately 53% for Pinnacle West and 54% for APS. The provisions regarding interest
94
coverage require a minimum cash coverage of two times the interest requirements for each of the Company and APS. Based on 2004 results, the coverages were approximately 4 times for the Company and 4 times for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants.
All of Pinnacle West’s bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under other agreements. All of APS’ bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under other agreements. Pinnacle West’s and APS’ credit agreements generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in our financial condition or financial prospects, except that Pinnacle West and APS do not have a material adverse change restriction for revolver borrowings equal to outstanding commercial paper amounts.
The following is a list of principal payments due on Pinnacle West’s total long-term debt and capitalized lease requirements:
7. Common Stock and Treasury Stock
Our common stock and treasury stock activity during each of the three years 2004, 2003 and 2002 is as follows (dollars in thousands):
95
8. Retirement Plans and Other Benefits
Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. Effective January 1, 2003, Pinnacle West sponsored a new account balance plan for all new employees in place of the defined benefit plan and, as of April 1, 2003, the plan was offered as an alternative to the defined benefit plan for all existing employees. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all of our employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors. Our employees do not contribute to the plans. Generally, we calculate the benefits based on age, years of service and pay.
Pinnacle West also sponsors other postretirement benefits for the employees of Pinnacle West and our subsidiaries. We provide medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plans, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits.
Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans.
96
On December 8, 2003, the President signed the “Medicare Prescription Drug, Improvement and Modernization Act of 2003” (the Act). One feature of the Act is a government subsidy of prescription drug cost. The FASB issued FSP 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” to address the accounting for the effects of the Act. During the third quarter of 2004, we retroactively adopted the provisions of FSP 106-2, resulting in the remeasurement of our postretirement benefit plans’ accumulated postretirement benefit obligation as of December 31, 2003. The impact of the subsidy is a decrease in the accumulated projected benefit obligation of approximately $65 million and a decrease of approximately $11 million in the net periodic postretirement benefit cost for 2004. The 2004 after-tax reduction to expense is approximately $5 million, excluding amounts capitalized as construction overhead or billed to electric plant participants.
The following table provides details of the plans’ benefit costs. Also included is the portion of these costs charged to expense, including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants (dollars in thousands):
97
The following table sets forth the plans’ changes in the benefit obligations for the plan years 2004 and 2003 (dollars in thousands):
The following table sets forth the qualified pension plan and other benefit plan changes in the fair value of plan assets for the years 2004 and 2003 (dollars in thousands):
The following table shows a reconciliation of the funded status of the plans to the amounts recognized on the Consolidated Balance Sheets as of December 31, 2004 and 2003 (dollars in thousands):
98
The following sets forth the details related to benefits included on the Consolidated Balance Sheets at December 31, 2004 and 2003 (dollars in thousands):
The following table sets forth the other comprehensive income arising from the change in additional minimum liability for the years ended December 31, 2004 and 2003 (dollars in thousands):
The following table sets forth the projected benefit obligation and the accumulated benefit obligation for pension plans in excess of plan assets for the plan years 2004 and 2003 (dollars in thousands):
Below are the weighted-average assumptions for both the pension and other benefits used to determine each respective benefit obligation and net periodic benefit cost:
99
In selecting the pretax expected long-term rate of return on plan assets we consider past performance and economic forecasts for the types of investments held by the plan. For the year 2005 we are assuming a 9% rate of return on plan assets. As recent history has demonstrated, markets may decline and increase dramatically. However, we believe the long-term rate of return on plan assets of 9% is reasonable given our asset allocation in relation to historical and expected future performance.
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% change in the assumed initial and ultimate health care cost trend rates would have the following effects (dollars in millions):
Plan Assets
Pinnacle West’s qualified pension plan asset allocation at December 31, 2004 and 2003 is as follows:
100
The Board of Directors has established an investment policy for the pension plan assets and has delegated oversight of the plan assets to an Investment Management Committee. The investment policy sets forth the objective of providing for future pension benefits by maximizing return consistent with acceptable levels of risk. The primary investment strategies are diversification of assets, stated asset allocation targets and ranges, prohibition of investments in Pinnacle West securities, and external management of plan assets.
Pinnacle West’s other postretirement benefit plans’ asset allocation at December 31, 2004 and 2003, is as follows:
The Investment Management Committee, described above, has also been delegated oversight of the plan assets for the postretirement benefit plans. The investment policy for other postretirement benefit plans assets is similar to that of the pension plan assets described above.
Contributions
The minimum required contribution to be made to our pension plan in 2005 is estimated to be approximately $50 million. The contribution to be made to other postretirement benefit plans in 2005 is estimated to be approximately $40 million. APS’ share is approximately 92% of both plans.
Estimated Future Benefit Payments
Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter are estimated to be as follows (dollars in thousands):
101
Employee Savings Plan Benefits
Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and subsidiaries. In 2004 APS represented 91% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account. Under this plan, the Company matches a percentage of the participants’ contributions in the form of Pinnacle West stock. After a five year vesting period, participants have an option to transfer the Company matching contributions out of the Pinnacle West Stock Fund to other investment funds within the plan. At December 31, 2004, approximately 22% of total plan assets were in Pinnacle West stock. Pinnacle West recorded expenses for this plan of approximately $5 million for each of the years 2004, 2003 and 2002. APS recorded expenses for this plan of approximately $5 million in 2004, $5 million in 2003 and $4 million in 2002.
9. Leases
In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale leaseback transactions. APS accounts for these leases as operating leases. The gain resulting from the transaction of approximately $140 million was deferred and is being amortized to operations and maintenance expense over 29.5 years, the original term of the leases. There are options to renew the leases for two additional years and to purchase the property for fair market value at the end of the lease terms. Rent expense is calculated on a straight-line basis. See Note 20 for a discussion of VIEs, including the SPEs involved in the Palo Verde sale leaseback transactions.
In addition, we lease certain land, buildings, equipment, vehicles and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates.
Total lease expense recognized in the Consolidated Statements of Income was $69 million in 2004, $67 million in 2003 and $67 million in 2002.
The amounts to be paid for the Palo Verde Unit 2 leases are approximately $49 million per year for the years 2005 to 2015.
Estimated future minimum lease payments for Pinnacle West’s operating leases are approximately as follows (dollars in millions):
102
10. Jointly-Owned Facilities
APS shares ownership of some of its generating and transmission facilities with other companies. Pinnacle West Energy shares ownership of its Silverhawk Plant. Our share of operating and maintaining these facilities is included in the Consolidated Statements of Income in operations and maintenance expense. The following table shows APS’ and Pinnacle West Energy’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2004 (dollars in thousands):
103
11. Commitments and Contingencies
Spent Nuclear Fuel and Waste Disposal
Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before 2010 and it does not intend to begin accepting spent nuclear fuel prior to that date. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims. Arizona Public Service Company v. United States of America, United States Court of Federal Claims, 03-2832C.
In February 2002, the Secretary of Energy recommended to President Bush that the Yucca Mountain, Nevada site be developed as a permanent repository for spent nuclear fuel. The President transmitted this recommendation to Congress and the State of Nevada vetoed the President’s recommendation. Congress approved the Yucca Mountain site, overriding the Nevada veto. The State of Nevada has filed several lawsuits relating to the Yucca Mountain site. We cannot currently predict what further steps will be taken in this area.
APS has existing fuel storage pools at Palo Verde and is operating a new facility for on-site dry storage of spent nuclear fuel. With the existing storage pools and the addition of the new facility, APS believes spent nuclear fuel storage or disposal methods will be available for use by Palo Verde to allow its continued operation through the term of the operating license for each Palo Verde unit.
Although some low-level waste has been stored on-site in a low-level waste facility, APS is currently shipping low-level waste to off-site facilities. APS currently believes interim low-level waste storage methods are or will be available for use by Palo Verde to allow its continued operation and to safely store low-level waste until a permanent disposal facility is available.
APS currently estimates it will incur $115 million (in 2004 dollars) over the life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. As of December 31, 2004, APS had spent $11 million for on-site interim spent nuclear fuel storage. APS has recorded a regulatory asset of $11 million and is currently seeking recovery of these costs through future rates (see “APS General Rate Case; 2004 Settlement Agreement” in Note 3).
APS believes that scientific and financial aspects of the issues of spent nuclear fuel and low-level waste storage and disposal can be resolved satisfactorily. However, APS acknowledges that their ultimate resolution in a timely fashion will require political resolve and action on national and regional scales which APS is less able to predict. APS expects to vigorously protect and pursue its rights related to this matter.
104
Nuclear Insurance
The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $101 million, subject to an annual limit of $10 million per incident. Based on APS’ interest in the three Palo Verde units, APS’ maximum potential assessment per incident for all three units is approximately $88 million, with an annual payment limitation of approximately $9 million.
The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.
Purchased Power and Fuel Commitments
APS and Pinnacle West are parties to various purchased power and fuel contracts with terms expiring from 2005 through 2025 that include required purchase provisions. We estimate the contract requirements to be approximately $187 million in 2005; $90 million in 2006; $81 million in 2007; $66 million in 2008; $68 million in 2009 and $363 million thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.
Of the various purchased power and fuel contracts mentioned above some of those contracts have take-or-pay provisions. The contracts APS has for the supply of its coal supply have take-or-pay provisions. The current take-or-pay coal contracts have terms that expire in 2016.
The following table summarizes the estimated take-or-pay commitments for the existing terms (dollars in millions):
105
Coal Mine Reclamation Obligations
APS must reimburse certain coal providers for amounts incurred for coal mine reclamation. APS’ coal mine reclamation obligation was $61 million at December 31, 2004 and $60 million at December 31, 2003 and is included in deferred credits-other on the Consolidated Balance Sheets.
California Energy Market Issues and Refunds in the Pacific Northwest
FERC In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California during a specified time frame. APS was a seller and a purchaser in the California markets at issue, and to the extent that refunds are ordered, APS should be a recipient as well as a payor of such amounts. The FERC is still considering the evidence and refund amounts have not yet been finalized. APS does not anticipate material changes in its exposure and still believes, subject to the finalization of the revised proxy prices, that it will be entitled to a net refund.
On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including the Company, failed to properly file rate information at the FERC in connection with sales to California from 2000 to the present under market-based rates. State of California v. British Columbia Power Exchange et al., Docket No. EL02-71-000. The complaint requests the FERC to require the wholesale sellers to refund any rates that are “found to exceed just and reasonable levels.” This complaint was dismissed by the FERC and the State of California appealed the matter to the Ninth Circuit Court of Appeals. In an order issued September 9, 2004, the Ninth Circuit upheld the FERC’s authority to permit market-based rates, but rejected the FERC’s claim that it was without authority to consider retroactive refunds when a utility has not strictly adhered to the quarterly reporting requirements of the market-based rate system. On September 9, 2004, the Ninth Circuit remanded the case to the FERC for further proceedings. State of California ex rel. Bill Lockyer, Attorney General v. FERC, No. 02-73093. Several of the intervenors in this appeal filed a petition for rehearing of this decision on October 25, 2004. The outcome of the further proceedings cannot be predicted at this time.
The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision has now been appealed to the Court of Appeals (Ninth Circuit). Although the FERC ruling in the Pacific Northwest matter is being appealed and the FERC has not yet calculated the specific refund amounts due in California, we do not expect that the resolution of these issues, as to the amounts alleged in the proceedings, will have a material adverse impact on our financial position, results of operations or liquidity.
On March 26, 2003, FERC made public a Final Report on Price Manipulation in Western Markets, prepared by its staff and covering spot markets in the West in 2000 and 2001. The report stated that a significant number of entities who participated in the California markets during the 2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the ISO tariff. After reviewing the matter, along with the data supplied by APS, the FERC staff moved to dismiss the claims against APS and to dismiss the proceeding. The motion to dismiss was granted by the FERC on January 22, 2004. Certain parties have sought rehearing of this order, and that request is pending.
106
California Civil Energy Market Litigation The State of California and others have filed various claims, which have now been consolidated, against several power suppliers to California alleging antitrust violations. Wholesale Electricity Antitrust Cases I and II, Superior Court in and for the County of San Diego, Proceedings Nos. 4204-00005 and 4204-00006. Two of the suppliers who were named as defendants in those matters, Reliant Energy Services, Inc. (and other Reliant entities) and Duke Energy and Trading, LLP (and other Duke entities), filed cross-claims against various other participants in the PX and California independent system operator markets, including APS, attempting to expand those matters to such other participants. APS has not yet filed a responsive pleading in the matter, but APS believes the claims by Reliant and Duke as they relate to APS are without merit.
APS was also named in a lawsuit regarding wholesale contracts in California, which, after moving to state court, has been removed to the federal court for a second time. James Millar, et al. v. Allegheny Energy Supply, et al., San Francisco Superior Court, Case No. 407867, U.S. District Court (Northern District) C-04-0519 SBA. The First Amended Complaint alleges basically that the contracts entered into were the result of an unfair and unreasonable market, in violation of California unfair competition laws. The PX has filed a lawsuit against the State of California regarding the seizure of forward contracts and the State has filed a cross complaint against APS and numerous other PX participants. Cal PX v. The State of California, Superior Court in and for the County of Sacramento, JCCP No. 4203. Various motions continue to be filed, and we currently believe these claims will have no material adverse impact on our financial position, results of operations or liquidity.
Consolidated capital expenditures in 2005 are estimated to be (dollars in millions):
Pursuant to the terms of a comprehensive settlement entered into in 1996 with El Paso Natural Gas Company, the rates charged for natural gas transportation are subject to a rate moratorium through December 31, 2005.
On July 9, 2003 the FERC issued an order that altered the capacity rights of parties to the 1996 settlement but maintained the cost responsibility provisions agreed to by parties to that settlement. The D.C. Court of Appeals recently upheld the FERC’s authority to alter the capacity rights of parties to the settlement. With respect to the FERC’s authority to maintain the cost responsibility provisions of the settlement, a party has sought appellate review and is seeking to reallocate the costs responsibility associated with the changed contractual obligations in a way that would be less favorable to APS and Pinnacle West Energy than under the FERC’s July 9, 2003 order. Should this party prevail on this point, APS and Pinnacle West Energy’s annual capacity cost could be increased by approximately $3 million per year, from September 2003 through December 2005.
107
El Paso is required under the terms of the 1996 settlement to file a new rate case by July 1, 2005, with new rates to become effective on January 1, 2006. APS cannot currently assess the financial impact that El Paso’s filing could have on rates.
Navajo Nation Litigation
In June 1999, the Navajo Nation served Salt River Project with a lawsuit naming Salt River Project, several Peabody Coal Company entities (collectively, “Peabody”), Southern California Edison Company and other defendants, and citing various claims in connection with the renegotiations of the coal royalty and lease agreements under which Peabody mines coal for the Navajo Generating Station and the Mohave Generating Station. The Navajo Nation v. Peabody Holding Company, Inc., et al., United States District Court for the District of Columbia, CA-99-0469-EGS (the “D.C. Lawsuit”). APS is a 14% owner of the Navajo Generating Station, which Salt River Project operates. The D.C. Lawsuit alleges, among other things, that the defendants obtained a favorable coal royalty rate by improperly influencing the outcome of a federal administrative process under which the royalty rate was to be adjusted. The suit seeks $600 million in damages, treble damages, punitive damages of not less than $1 billion, and the ejection of defendants “from all possessory interests and Navajo Tribal lands arising out of the [primary coal lease]”. In July 2001, the court dismissed all claims against Salt River Project.
In January, 2005, Peabody served APS with a lawsuit naming APS and the other Navajo Generating Station participants and seeking, among other things, a declaration that the participants “are obligated to reimburse Peabody for any royalty, tax, or other obligation arising out of the D.C. Lawsuit”. Peabody Western Coal Company v. Salt River Project Agricultural Improvement and Power District, et al., Circuit Court for the City of St. Louis, Division No. 1, Cause No. 042-08561. Based on APS’ ownership interest in the Navajo Generating Station, APS could be liable for up to 14% of any such obligation. Because the litigation is in preliminary stages, APS cannot currently predict the outcome of this matter.
Litigation
We are party to various other claims, legal actions and complaints arising in the ordinary course of business, including but not limited to environmental matters related to the Clean Air Act, Navajo Nation issues and EPA and ADEQ issues. In our opinion, the ultimate resolution of these matters will not have a material adverse effect on our financial position, results of operations or liquidity.
12. Asset Retirement Obligations
APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation, transmission and distribution assets. The Palo Verde asset retirement obligation primarily relates to final plant decommissioning. This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant. The non-nuclear generation asset retirement obligations primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term. Some of APS’ transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal. These agreements have a history of uninterrupted renewal that APS expects to continue. As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such distribution and transmission assets. The asset retirement obligations associated with our non-regulated assets are immaterial.
To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in fixed income and domestic equity securities and classifies them as available for sale. The following table shows the cost and fair value of APS’ nuclear decommissioning trust fund assets which are on the Consolidated Balance Sheets at December 31, 2004 and December 31, 2003 (dollars in millions):
108
The following schedule shows the change in our asset retirement obligations during the years ended December 31, 2004 and 2003 (dollars in millions):
In accordance with SFAS No. 71, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal. At December 31, 2004, regulatory liabilities shown on Pinnacle West’s Consolidated Balance Sheets included approximately $462 million of estimated future removal costs that are not considered legal obligations.
109
13. Selected Quarterly Financial Data (Unaudited)
The following note presents quarterly financial information for 2004 and 2003. We are disclosing originally reported amounts and revised amounts in the first and second quarters of 2004 due to the adoption of FSP 106-2, which was implemented on June 30, 2004 (see Note 8) and in each period for the reclassification of NAC as discontinued operations (see Note 22).
Consolidated quarterly financial information for 2004 and 2003 is as follows (dollars in thousands, except per share amounts):
110
111
Earnings per share:
112
14. Fair Value of Financial Instruments
We believe that the carrying amounts of our cash equivalents are reasonable estimates of their fair values at December 31, 2004 and 2003 due to their short maturities.
We hold investments in debt securities for purposes other than trading. We believe that the carrying amounts of these investments represent reasonable estimates of their fair values at December 31, 2004 and 2003 due to the short-term reset of interest rates.
We also hold investments in fixed income and domestic equity securities for purposes other than trading. The December 31, 2004 and 2003 fair values of such investments, which we determine by using quoted market prices, approximate their carrying amount. For further information, see disclosure of cost and fair value of APS’ nuclear decommissioning trust fund assets in Note 12.
On December 31, 2004, the carrying value of our long-term debt (excluding capitalized lease obligations) was $3.19 billion, with an estimated fair value of $3.30 billion. The carrying value of our long-term debt (excluding capitalized lease obligations) was $3.31 billion on December 31, 2003, with an estimated fair value of $3.46 billion. The fair value estimates are based on quoted market prices of the same or similar issues.
15. Earnings Per Share
The following table presents earnings per weighted average common share outstanding for the years ended December 31, 2004, 2003 and 2002:
Dilutive stock options increased average common shares outstanding by approximately 135,000 shares in 2004, 140,000 shares in 2003 and 61,000 shares in 2002. Total average common shares outstanding for the purposes of calculating diluted earnings per share were 91,532,473 shares in 2004, 91,405,134 shares in 2003 and 84,963,921 shares in 2002.
113
Options to purchase 1,058,616 shares of common stock were outstanding at December 31, 2004 but were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares. Options to purchase shares of common stock that were not included in the computation of diluted earnings per share were 2,291,646 at December 31, 2003 and 1,629,958 at December 31, 2002.
16. Stock-Based Compensation
Pinnacle West offers stock-based compensation plans for officers and key employees of the Company and our subsidiaries.
In May 2002, shareholders approved the 2002 Long-Term Incentive Plan (2002 plan), which allows Pinnacle West to grant performance shares, stock ownership incentive awards and non-qualified and performance-accelerated stock options to key employees. The Company has reserved 6 million shares of common stock for issuance under the 2002 plan. No more than 1.8 million shares may be issued in relation to performance share awards and stock ownership incentive awards. The plan also provides for the granting of new non-qualified stock options at a price per share not less than the fair market value of the common stock at the time of grant. The stock options vest over three years, unless certain performance criteria are met, which can accelerate the vesting period. The term of the option cannot be longer than 10 years and the option cannot be repriced during its term.
The 1994 plan includes outstanding options but no new options will be granted under the plan. Options vested one-third of the grant per year beginning one year after the date the option is granted and expire ten years from the date of the grant. The 1994 plan also provided for the granting of any combination of shares of restricted stock, stock appreciation rights or dividend equivalents.
In the third quarter of 2002, we began applying the fair value method of accounting for stock-based compensation, as provided for in SFAS No. 123. The fair value method of accounting is the preferred method. In accordance with the transition requirements of SFAS No. 123, we applied the fair value method prospectively, beginning with 2002 stock grants. In prior years, we recognized stock compensation expense based on the intrinsic value method allowed in APB No. 25.
In addition, see Note 2 for discussion of a new standard on share based payments (SFAS No. 123R).
Total stock-based compensation cost, including restricted stock, performance shares, stock options, and stock ownership incentives was $8 million in 2004, $6 million in 2003 and $5 million in 2002 for Pinnacle West, and $6 million in 2004, $3 million in 2003 and $3 million in 2002 for APS.
The following table is a summary of the status of outstanding stock options under our equity incentive plans as of December 31, 2004, 2003 and 2002 and changes during the years ending on those dates:
114
The following table summarizes information about our stock options at December 31, 2004:
The following table is a summary of the amount and weighted-average grant date fair value of stock compensation awards granted, other than options, during the years ended December 31, 2004, 2003 and 2002:
115
17. Business Segments
We have three principal business segments (determined by products, services and the regulatory environment):
In 2004, our other segment includes a $35 million gain ($21 million after-tax) related to the sale of El Dorado’s limited partnership interest in the Phoenix Suns. The other segment also includes activity related to APS Energy Services’ non-commodity trading activities, as well as the parent company and other subsidiaries.
Financial data for the years ended December 31, 2004, 2003 and 2002 by business segments is provided as follows (dollars in millions):
116
117
18. Derivative and Energy Trading Accounting
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates. We manage risks associated with these market fluctuations by utilizing various instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge our exposure to changes in interest rates and to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. As of December 31, 2004, we hedged exposures to the price variability of the commodities for a maximum of eight years. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.
We recognize all derivatives, except those which receive a scope exception, as either assets or liabilities on the balance sheet and measure those instruments at fair value in accordance with SFAS No. 133, as amended by SFAS No. 149. Derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business receive the normal purchase and sales exception and are accounted for under the accrual method of accounting. Changes in the fair value of derivative instruments are recognized periodically in income unless certain hedge criteria are met. For cash flow hedges, changes in the fair value of the derivative are recognized in common stock equity (as a component of other comprehensive income (loss)). For fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item associated with the hedged risk are recognized in earnings. We use cash flow hedges to limit our exposure to cash flow variability on forecasted transactions. We use fair value hedges to limit our exposure to changes in fair value of an asset or liability.
We assess hedge effectiveness both at inception and on a continuing basis. Hedge effectiveness is related to the degree to which the derivative contract and the hedged item are correlated. It is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. We exclude the time value of certain options from our assessment of hedge effectiveness. Any change in the fair value resulting from ineffectiveness, or the amount by which the derivative contract and the hedged commodity are not directly correlated, is recognized immediately in net income.
Both non-trading and trading derivatives that do not receive a scope exception are classified as assets and liabilities from risk management and trading activities on the Consolidated Balance Sheets. Certain of our non-trading derivatives qualify for cash flow hedge accounting treatment. Non-trading derivatives, or any portion thereof that are not effective hedges, are adjusted to fair value through income. Gains and losses related to non-trading derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or purchased power and fuel expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earnings. If it becomes probable that a forecasted transaction will not occur, we discontinue the use of hedge accounting and recognize in income the unrealized gains and losses that were previously recorded in other comprehensive income (loss). In the event a non-trading derivative is terminated or settled, the unrealized gains and losses remain in other comprehensive income (loss), and are recognized in income when the underlying transaction impacts earnings.
118
All gains and losses (realized and unrealized) on trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Consolidated Statements of Income on a net basis. Trading contracts that do not meet the definition of a derivative are accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received.
In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and purchased power and fuel costs in our Consolidated Statement of Income, but this does not impact our financial condition, net income or cash flows.
In November 2003, the FASB revised its derivative guidance in DIG Issue No. C15, “Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity.” Effective January 1, 2004, the new guidance changed the criteria for the normal purchases and sales scope exception for electricity contracts. The implementation of this guidance did not have a material impact on our consolidated financial statements.
During 2002, the EITF discussed EITF 02-3 and reached a consensus on certain issues. EITF 02-3 rescinded EITF 98-10 and was effective October 25, 2002 for any new contracts, and on January 1, 2003 for existing contracts, with early adoption permitted. We adopted the EITF 02-3 guidance for all contracts in the fourth quarter of 2002. We recorded a $66 million after-tax charge in net income as a cumulative effect adjustment for the previously recorded accumulated unrealized mark-to-market on energy trading contracts that did not meet the accounting definition of a derivative.
Cash Flow Hedges
The changes in the fair value of our hedged positions included in the Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002 are comprised of the following (dollars in thousands):
During the twelve months ending December 31, 2005, we estimate that a net gain of $44 million before income taxes will be reclassified from accumulated other comprehensive loss as an offset to the effect on earnings of market price changes for the related hedged transactions.
119
Our assets and liabilities from risk management and trading activities are presented in two categories, consistent with our business segments:
The following table summarizes our assets and liabilities from risk management and trading activities at December 31, 2004 and 2003 (dollars in thousands):
December 31, 2004
December 31, 2003
Cash or other assets may be required to serve as collateral against our open positions on certain energy-related contracts. Collateral provided to counterparties is $1 million at December 31, 2004 and $1 million at December 31, 2003, and is included in other current assets on the Consolidated Balance Sheet. Collateral provided to us by counterparties is $18 million at
120
December 31, 2004 and $12 million at December 31, 2003, and is included in other current liabilities on the Consolidated Balance Sheet.
Fair Value Hedges
On January 29, 2004, we entered into two fixed-for-floating interest rate swap transactions on our $300 million 6.4% Senior Notes. The purpose of these hedges is to protect against significant fluctuations in the fair value of our debt. Our interest rate swaps are considered to be fully effective with any resulting gains or losses on the derivative offset by a similar loss or gain amount on the underlying fair value of debt. The fair value of the interest rate swaps was $2.6 million at December 31, 2004 and is included in investments and other assets with the corresponding offset in long-term debt less current maturities on the Consolidated Balance Sheets.
We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including two counterparties for which a worst case exposure represents approximately 35% of Pinnacle West’s $391 million of risk management and trading assets as of December 31, 2004. Our risk management process assesses and monitors the financial exposure of these and all other counterparties. Despite the fact that the great majority of trading counterparties are rated as investment grade by the credit rating agencies, including the counterparties noted above, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of major energy companies, municipalities, local distribution companies and financial institutions. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. In many contracts, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties. See Note 1 “Derivative” for a discussion of our credit valuation adjustment policy.
19. Other Income and Other Expense
The following table provides detail of other income and other expense for the years ended December 31, 2004, 2003 and 2002 (dollars in thousands):
121
20. Variable Interest Entities
In the first quarter of 2004, we adopted FIN No. 46R, “Consolidation of Variable Interest Entities” for all non-SPE contractual arrangements. SunCor has certain land development arrangements that are required to be consolidated under FIN No. 46R. The assets and non-controlling
122
interests reflected in our Consolidated Balance Sheets related to these arrangements were approximately $34 million at December 31, 2004.
21. Guarantees
We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our unregulated subsidiaries. Our parental guarantees related to Pinnacle West Energy consist of equipment and performance guarantees related to our generation construction program, and long-term service agreement guarantees for new power plants. Our credit support instruments enable APS Energy Services to offer commodity energy and energy-related products. Non-performance or payment under the original contract by our unregulated subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Consolidated Balance Sheets related to Pinnacle West’s guarantees on behalf of its subsidiaries. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantee. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at December 31, 2004 are as follows (dollars in millions):
At December 31, 2004, we had entered into approximately $39 million of letters of credit which support various transmission and construction agreements. These letters of credit expire in 2005 and 2006. We intend to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required. At December 31, 2004, Pinnacle West has approximately $3 million of letters of credit related to workers’ compensation expiring in 2006.
APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2004, approximately $200 million of letters of credit were outstanding to support existing pollution control bonds of approximately $200 million. The letters of credit are available to fund the payment of principal and interest of such debt obligations. In July 2004, $150 million of these letters of credit were renewed for a three-year term and expire in 2007. The remainder expire in 2005. APS has also entered into approximately $102 million of letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions (see Note 9 for further details on the Palo Verde sale leaseback transactions). These letters of credit expire in 2005. Additionally, APS has approximately $5 million of letters of credit related to counterparty collateral requirements expiring in 2006. APS intends to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.
We provide indemnifications relating to liabilities arising from or related to certain of our agreements. APS has provided indemnifications to the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification and therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. Based on historical
123
experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnifications is likely.
22. Discontinued Operations
The following table provides a summary of SunCor and NAC income (loss) from discontinued operations (after income taxes) for the years ended December 31, 2004, 2003 and 2002 (dollars in millions):
SunCor
Certain components of SunCor’s real estate sales activities, which are included in the real estate segment, are required to be reported as discontinued operations on Pinnacle West’s Consolidated Statements of Income in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Among other guidance, SFAS No. 144 prescribes accounting for discontinued operations and defines certain activities as discontinued operations.
In the second quarter of 2002, SunCor sold a retail center, but maintained a continuing involvement through a management contract. In the first quarter of 2003, this management contract was canceled. As a result, the after-tax gain of $6 million ($10 million pre-tax) recorded in operations in 2002 related to this property was reclassified as discontinued operations on our Consolidated Statements of Income. The income from discontinued operations in the year ended December 31, 2002 primarily reflects this sale.
In 2003, SunCor sold its water utility company, which resulted in an after-tax gain of $8 million ($14 million pretax). The amounts of the gain on the sale and operating income of the water utility company in 2003 and 2002 are classified as discontinued operations on Pinnacle West’s Consolidated Statements of Income.
In the fourth quarter of 2003, SunCor sold a retail center, which resulted in an after-tax gain of $2 million ($3 million pretax). The gain on the sale and the operating income related to this property in 2003 are classified as discontinued operations on Pinnacle West’s Consolidated Statements of Income. There were no prior-year operations related to this retail center.
In 2004, SunCor sold commercial property, which resulted in an after-tax gain of $1 million ($2 million pretax). The gain on the sale and the operating income related to this property in 2004 are classified as discontinued operations on Pinnacle West’s Consolidated Statements of Income. There were no prior-year operations related to this property.
The following table provides SunCor’s revenue and income before income taxes (including the gains on disposals as noted above) related to properties classified as discontinued operations on
124
Pinnacle West’s Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002 (dollars in millions):
NAC
In July 2004, we entered into an agreement to sell our investment in NAC. The transaction closed on November 18, 2004 and resulted in a pre-tax gain of $4 million, which is classified as discontinued operations in 2004. El Dorado began consolidating the operations of NAC in the third quarter of 2002. All related revenues and expenses for NAC have been reclassified to discontinued operations for the years ended December 31, 2003 and 2002 on Pinnacle West’s Consolidated Statements of Income.
The following table provides the revenue and income before taxes (including the gain on disposal as noted above) for El Dorado’s investment in NAC that was classified as discontinued operations for the years ended December 31, 2004, 2003 and 2002 (dollars in millions):
Percentage-of-Completion – NAC
Certain NAC contract revenues are accounted for under the percentage-of-completion method. Revenues are recognized based upon total costs incurred to date compared to total costs expected to be incurred for each contract. Revisions in contract revenue and cost estimates are reflected in the accounting period when known. Provisions are made for the full amounts of anticipated losses in the periods in which they are first determined. Changes in job performance, job conditions and estimated profitability, including those arising from contract penalty provisions and final contract settlements, may result in revisions to costs and income, and are recognized in the period in which revisions are determined. Profit incentives are included in revenues when their realization is reasonably assured.
Contract costs include all direct material and labor costs and those indirect costs related to contract performance, such as indirect labor, supplies, tools, repairs and depreciation costs. General and administrative costs are charged to expense as incurred.
125
Assets and Liabilities Related to Discontinued Operations
Due to the sale of NAC, all NAC assets and liabilities have been reclassified to assets and liabilities related to discontinued operations on the Consolidated Balance Sheets at December 31, 2003 and are provided in the following table (dollars in thousands):
126
MANAGEMENT’S REPORT ON INTERNAL CONTROLOVER FINANCIAL REPORTING(ARIZONA PUBLIC SERVICE COMPANY)
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13(a)-15(f). Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control – Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2004. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and relates also to the Company’s financial statements.
127
To the Board of Directors and Stockholders ofArizona Public Service CompanyPhoenix, Arizona
We have audited the accompanying balance sheets of Arizona Public Service Company (the “Company”) as of December 31, 2004 and 2003, and the related statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule, an opinion on management’s assessment, and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audits.
128
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
129
ARIZONA PUBLIC SERVICE COMPANYSTATEMENTS OF INCOME(dollars in thousands)
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.
130
ARIZONA PUBLIC SERVICE COMPANYBALANCE SHEETS(dollars in thousands)
131
132
ARIZONA PUBLIC SERVICE COMPANYSTATEMENTS OF CASH FLOWS(dollars in thousands)
133
ARIZONA PUBLIC SERVICE COMPANYSTATEMENTS OF CHANGES IN COMMON STOCK EQUITY(dollars in thousands)
134
Certain notes to Arizona Public Service Company’s financial statements are combined with the notes to Pinnacle West Capital Corporation’s consolidated financial statements. Listed below are the consolidated notes to Pinnacle West Capital Corporation’s consolidated financial statements, the majority of which also relate to Arizona Public Service Company’s financial statements. In addition, listed below are the supplemental notes which are required disclosures for Arizona Public Service Company and should be read in conjunction with Pinnacle West Capital Corporation’s Consolidated Notes.
135
ARIZONA PUBLIC SERVICE COMPANYSUPPLEMENTAL NOTES TO THE FINANCIAL STATEMENTS
S-1. Summary of Significant Accounting Polices
Pinnacle West offers stock-based compensation plans for officers and key employees of APS. In 2002, APS began applying the fair value method of accounting for stock-based compensation, as provided for in SFAS No. 123, “Accounting for Stock-Based Compensation.” The fair value method of accounting is the preferred method. In accordance with the transition requirements of SFAS No. 123, APS applied the fair value method prospectively, beginning with 2002 stock grants. In prior years, APS recognized stock compensation expense based on the intrinsic value method allowed in Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.”
The following chart compares APS’ net income and stock compensation expense to what those items would have been if APS had recorded stock compensation expense based on the fair value method for all stock grants through 2004 (dollars in thousands):
S-2. Income Taxes
APS is included in our consolidated tax return. However, when we allocate income taxes to APS, we do so based on APS’ taxable income or loss alone.
136
The components of APS’ income tax expense are as follows (dollars in thousands):
On the APS Statements of Income, federal and state income taxes are allocated between operating income and other income.
The following chart compares APS’ pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands):
The following table sets forth the net deferred income tax liability recognized on the APS Balance Sheets (dollars in thousands):
137
S-3. Long-Term Debt Payments
The following is a list of principal payments due on APS’ total long-term debt and capitalized lease requirements:
S-4. Leases
Total lease expense recognized in the APS Statements of Income was $57 million in 2004, $66 million in 2003 and $57 million in 2002.
Estimated future minimum lease payments for APS’ operating leases are approximately as follows (dollars in millions):
138
\
S-5. Commitments and Contingencies
APS is party to various purchased power and fuel contracts with terms expiring from 2005 through 2025 that include required purchase provisions. APS estimates the contract requirements to be approximately $245 million in 2005; $125 million in 2006; $81 million in 2007; $66 million in 2008; $68 million in 2009 and $363 million thereafter. Included in these contract requirements is approximately $57 million in 2005 and $36 million in 2006 for related party purchases (see Note 3). However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.
139
S-6. Selected Quarterly Financial Data (Unaudited)
The following note presents quarterly financial information for 2004 and 2003. APS is disclosing originally reported amounts and revised amounts in the first and second quarters of 2004 due to the adoption of FSP 106-2 (see Note 8). Quarterly financial information for 2004 and 2003 is as follows (dollars in thousands):
S-7. Fair Value of Financial Instruments
APS believes that the carrying amounts of its cash equivalents are reasonable estimates of their fair values at December 31, 2004 and 2003 due to their short maturities.
APS holds investments in fixed income and domestic equity securities for purposes other than trading. The December 31, 2004 and 2003 fair values of such investments, which APS determines by using quoted market prices, approximate their carrying amount. For further information, see disclosure of cost and fair value of APS’ nuclear decommissioning trust fund assets in Note 12.
On December 31, 2004, the carrying value of APS’ long-term debt (excluding capitalized lease obligations) was $2.71 billion, with an estimated fair value of $2.81 billion. The carrying value of APS’ long-term debt (excluding capital lease obligations) was $2.61 billion on December 31,
140
2003, with an estimated fair value of $2.74 billion. The fair value estimates are based on quoted market prices of the same or similar issues.
S-8. Derivative and Energy Trading Accounting
APS is exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. As part of its overall risk management program, APS uses various commodity instruments that qualify as derivatives to hedge purchases and sales of electricity, fuels and emissions allowances and credits. As of December 31, 2004, APS hedged exposures to these risks for a maximum of three years.
The changes in the fair value of APS’ hedged positions included in the APS Statements of Income for the years ended December 31, 2004, 2003 and 2002 are comprised of the following (dollars in thousands):
During the twelve months ending December 31, 2005, APS estimates that a net gain of $23 million before income taxes will be reclassified from accumulated other comprehensive loss as an offset to the effect on earnings of market price changes for the related hedged transactions.
APS’ assets and liabilities from risk management and trading activities are presented in two categories:
The following table summarizes APS’ assets and liabilities from risk management and trading activities at December 31, 2004 and 2003 (dollars in thousands):
141
Cash or other assets may be required to serve as collateral against APS’ open positions on certain energy-related contracts. No collateral was provided to counterparties at December 31, 2004 or at December 31, 2003. Collateral provided to us by counterparties is $6 million at December 31, 2004 and $12 million at December 31, 2003, and is included in other current liabilities on the Balance Sheet.
S-9. Other Income and Other Expense
The following table provides detail of APS’ other income and other expense for the years ended December 31, 2004, 2003 and 2002 (dollars in thousands):
142
S-10. Related Party Transactions
From time to time, APS enters into transactions with Pinnacle West or Pinnacle West’s subsidiaries. The following table summarizes the amounts included in the APS Statements of Income and Balance Sheets related to transactions with affiliated companies (dollars in millions):
143
Electric revenues include sales of electricity to affiliated companies at contract prices. Purchased power includes purchases of electricity from affiliated companies at contract prices. The Company purchases electricity from and sells electricity to APS Energy Services; however, these transactions are settled net and reported net in accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in Issue No. 2-3.” See Note 18 for more information related to EITF 03-11. Intercompany receivables primarily include the amounts related to the loan APS made to Pinnacle West Energy and intercompany sales of electricity. Intercompany payables primarily include amounts related to the intercompany purchases of electricity. Intercompany receivables and payables are generally settled on a current basis in cash.
144
PINNACLE WEST CAPITAL CORPORATIONSCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS(dollars in thousands)
145
ARIZONA PUBLIC SERVICE COMPANYSCHEDULE II – RESERVE FOR UNCOLLECTIBLES(dollars in thousands)
146
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTSON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
(a) Disclosure Controls and Procedures
The term “disclosure controls and procedures” means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934 (the “Exchange Act”) (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to a company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of December 31, 2004. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.
APS’ management, with the participation of APS’ Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of APS’ disclosure controls and procedures as of December 31, 2004. Based on that evaluation, APS’ Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’ disclosure controls and procedures were effective.
(b) Management’s Annual Reports on Internal Control Over Financial Reporting
Reference is made to “Management’s Report on Internal Control Over Financial Reporting (Pinnacle West Capital Corporation)” on page 64 of this report and “Management’s Report on Internal Control Over Financial Reporting (Arizona Public Service Company)” on page 128 of this report.
(c) Attestation Reports of the Registered Public Accounting Firm
Reference is made to “Report of Independent Registered Public Accounting Firm” on page 65 of this report and “Report of Independent Registered Public Accounting Firm” on page 129 of this report on the internal control over financial reporting of Pinnacle West and APS, respectively.
(d) Changes In Internal Control Over Financial Reporting
The term “internal control over financial reporting” (defined in SEC Rule 13a-15(f)) refers to the process of a company that is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.
147
No change in Pinnacle West’s or APS’ internal control over financial reporting occurred during the fiscal quarter ended December 31, 2004 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’ internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
PART III
ITEM 10. DIRECTORS AND EXECUTIVEOFFICERS OF PINNACLE WEST
Reference is hereby made to “Information About Our Board and Its Committees and Our Corporate Governance,” “Election of Directors” and to “Section 16(a) Beneficial Ownership Reporting Compliance” in the Pinnacle West Proxy Statement relating to the Annual Meeting of Shareholders to be held on May 18, 2005 (the “2005 Proxy Statement”) and to the Supplemental Item – “Executive Officers of Pinnacle West” in Part I of this report.
Pinnacle West has adopted a Code of Ethics for Financial Professionals that applies to professional employees in the areas of finance, accounting, internal audit, energy risk management, marketing and trading financial control, tax, investor relations, and treasury and also includes Pinnacle West’s Chief Executive Officer, Chief Financial Officer, Controller, Treasurer, and officers holding substantially equivalent positions at Pinnacle West’s subsidiaries. The Code of Ethics for Financial Professionals is posted on Pinnacle West’s website at www.pinnaclewest.com. Pinnacle West intends to satisfy the requirements under Item 5.05 of Form 8-K regarding disclosure of amendments to, or waivers from, provisions of the Code of Ethics for Financial Professionals by posting such information on Pinnacle West’s website.
ITEM 11. EXECUTIVE COMPENSATION
Reference is hereby made to “Information About Our Board and Its Committees and Our Corporate Governance – How are Directors compensated?”; “Performance Graph”; and “Executive Compensation” in the 2005 Proxy Statement.
ITEM 12. SECURITY OWNERSHIP OFCERTAIN BENEFICIAL OWNERS AND MANAGEMENTAND RELATED STOCKHOLDER MATTERS
Security Ownership of Certain Beneficial Owners and Management
Reference is hereby made to “How Many Shares of Pinnacle West Stock are Owned by Management and Large Shareholders?” in the 2005 Proxy Statement.
Securities Authorized For Issuance Under Equity Compensation Plans
The following table sets forth information as of December 31, 2004 with respect to our compensation plans and individual compensation arrangements under which our equity securities were authorized for issuance.
148
Equity Compensation Plan Information
Equity Compensation Plans Approved By Security Holders
The Company has four equity compensation plans that were approved by its shareholders: the Pinnacle West Capital Corporation Stock Option and Incentive Plan, under which no new options may be granted; the Pinnacle West Capital Corporation Directors Stock Option Plan, under which no new options may be granted; the Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan, under which no stock awards may be granted; and the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan. See Note 16 for additional information regarding these plans.
Equity Compensation Plans Not Approved By Security Holders
The Company has one equity compensation plan, the Pinnacle West Capital Corporation 2000 Director Equity Plan (the “2000 Plan”), for which the approval of shareholders was not required.
Number of Shares Subject to the 2000 Plan. The total number of shares of the Company’s common stock granted under the 2000 Plan may not exceed 200,000. In the case of a significant corporate event, such as a reorganization, merger or consolidation, the 2000 Plan provides for adjustment of the above limit, the number of shares to be awarded automatically to eligible non-employee directors and the number of shares of the Company’s common stock non-employee directors are required to own to receive an annual grant of common stock under the 2000 Plan.
Eligibility for Participation. Only non-employee directors may participate in the 2000 Plan. A non-employee director is an individual who is a director of the Company but who is not also an employee of the Company or any of its subsidiaries.
Terms of Awards. The 2000 Plan provides for: (1) annual grants of common stock to eligible non-employee directors, (2) discretionary grants of common stock to eligible non-employee directors and (3) grants of nonqualified stock options to eligible non-employee directors.
149
Annual Grants of Stock
Each individual who is a non-employee director as of July 1 of a calendar year, and who meets requirements of ownership of the Company’s common stock set forth below, will receive 900 shares of the Company’s common stock for such calendar year. In the first calendar year in which a non-employee director is eligible to participate in the 2000 Plan, he or she must own at least 900 shares of the Company’s common stock as of December 31 of the same calendar year to receive a grant of 900 shares of the Company’s common stock. If the non-employee director owns 900 shares of common stock as of June 30, he or she will receive a grant of 900 shares of common stock as of July 1 of the same calendar year. If the non-employee director does not own 900 shares of the Company’s common stock as of June 30, but acquires the necessary shares on or before December 31 of the same year, he or she will receive a grant of 900 shares of common stock within a reasonable time after the Company verifies that the requisite number of shares has been acquired. In each subsequent year, the number of shares of the Company’s common stock the non-employee director must own to receive a grant of 900 shares of common stock will increase by 900 shares, until reaching a maximum of 4,500 shares. In each of the subsequent years, the non-employee director must own the requisite number of shares of the Company’s common stock as of June 30 of the relevant calendar year.
Discretionary Grants of Stock
The Human Resources Committee of the Board of Directors administers the 2000 Plan and may grant shares of the Company’s common stock to non-employee directors in its discretion. No discretionary grants of common stock have been made under the 2000 Plan.
Grants of Non-qualified Stock Options
The Committee can grant non-qualified stock options under the 2000 Plan. The terms and the conditions of the option grant, including the exercise price per share, which may not be less than fair market value on the date of grant, will be set by the Committee in a written award agreement. The Committee will determine the time or times at which any such options may be exercised in whole or in part. The Committee will also determine the performance or other conditions, if any, that must be satisfied before all or part of an option may be exercised. Any such options granted to a participant will expire on the tenth anniversary date of the date of grant, unless the option is earlier terminated, forfeited or surrendered pursuant to a provision of the 2000 Plan or the applicable award agreement. Notwithstanding the foregoing, if a participant ceases to be a Company director for any reason, including death or disability, any such options held by that participant will expire on the second anniversary of the date on which the participant ceased to be a Company director, unless otherwise provided in the applicable award agreement. Unless the Committee provides otherwise, no such options may be sold, transferred, pledged, assigned or otherwise alienated, other than by will, the laws of descent and distribution, or under any other circumstances allowed by the Committee. No options have been granted under the 2000 Plan.
150
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Reference is hereby made to “How Many Shares of Pinnacle West Stock are Owned by Management and Large Shareholders?”; “Executive Compensation – Human Resources Committee Interlocks and Insider Participation” and “What are the Company’s Executive Benefit Plans – Employment and Severance Agreements” in the 2005 Proxy Statement.
ITEM 14. PRINCIPAL ACCOUNTANTFEES AND SERVICES
Pinnacle West
Reference is hereby made to “Audit Matters – What fees were paid to APS’ independent accountants in 2004 and 2003?” and “– What are the Audit Committee’s pre-approval policies?” in the 2005 Proxy Statement.
The following fees were paid to our independent public accountants, Deloitte & Touche LLP, for the last two fiscal years:
Pinnacle West’s Audit Committee pre-approves each audit service and non-audit service to be provided by APS’ independent public accountants. The Audit Committee has delegated to the Chairman of the Audit Committee the authority to pre-approve audit and non-audit services to be performed by the independent public accountants if the services are not expected to cost more than $50,000. The Chairman must report any pre-approval decisions to the Audit Committee at its next scheduled meeting. All of the services performed by Deloitte & Touche LLP for APS were pre-approved by the Audit Committee.
151
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Financial Statements and Financial Statement Schedules
See the Index to Financial Statements and Financial Statement Schedule in Part II, Item 8.
Exhibits Filed
The documents listed below are being filed or have previously been filed on behalf of Pinnacle West or APS and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith.
152
153
154
155
156
157
158
159
160
161
162
163
164
165
166
167
168
169
170
171
172
173
174
175
176
177
178
179
180
181
182
183
184
185
186
a Reports filed under File No. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.
b Management contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 14(c) of Form 10-K.
c An additional document, substantially identical in all material respects to this Exhibit, has been entered into, relating to an additional Equity Participant. Although such additional document may differ in other respects (such as dollar amounts, percentages, tax indemnity matters, and dates of execution), there are no material details in which such document differs from this Exhibit.
d Additional agreements, substantially identical in all material respects to this Exhibit have been entered into with additional persons. Although such additional documents may differ in other respects (such as dollar amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit.
187
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Power of Attorney
We, the undersigned directors and executive officers of Pinnacle West Capital Corporation, hereby severally appoint Donald E. Brandt, Barbara M. Gomez and Nancy C. Loftin, and each of them, our true and lawful attorneys with full power to them and each of them to sign for us, and in our names in the capacities indicated below, any and all amendments to this Annual Report on Form 10-K filed with the Securities and Exchange Commission.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
188
189
We, the undersigned directors and executive officers of Arizona Public Service Company, hereby severally appoint Donald E. Brandt, Barbara M. Gomez and Nancy C. Loftin, and each of them, our true and lawful attorneys with full power to them and each of them to sign for us, and in our names in the capacities indicated below, any and all amendments to this Annual Report on Form 10-K filed with the Securities and Exchange Commission.
190
191
Exhibit Index